Agenda

Agenda

9:00

Paal Kibsgaard, CEO Schlumberger Limited

9:30

Mohammed Y Al Qahtani, SVP Upstream Saudi Aramco

10:00

Urs Hölzle, SVP Technical Infrastructure and Google Fellow, Google

10:30 am

Coffee Break

11:10

Keisuke Sadamori, Director for Energy Markets and Security International Energy Agency

11:40

Margareth Øvrum, EVP Technology, Projects & Drilling Statoil ASA

12:10

Ashok Belani, CTO Schlumberger Limited

12:45 pm

Lunch

1:45

Exhibition Open

1:45

Executive IT Program (invite only)

2:00

Technical Program, Executive Meetings

3:30 pm

Coffee Break

5:30

Close

7:00 pm

Buses depart for Gala Dinner at Palais Garnier Opera

2:00 pm Well Construction

Well collision avoidance management

  • S. Sawaryn (Consultant)

Well collision avoidance management

Well Construction
Wednesday, September 13
2:00 pm

The well collision avoidance management and principles outlined in the presentation are a culmination of the work and consensus of industry experts from both operators and service companies in the SPE Wellbore Positioning Technical Section. This is not a new subject, but current guidance is disparate, company specific, and occasionally contradictory. As a result, the guidance can be difficult to understand and implement. Standardization of the well collision avoidance rules, process, and nomenclature is required throughout the industry.

Well collision avoidance management is an excellent example of a drilling subject that requires faithful and meticulous coordination between multiple parties throughout the planning and execution stages. Failure to achieve this can result in an unplanned intersection with an existing well and the consequences can range from financial loss to a catastrophic blowout and loss of life. The process of well collision avoidance involves rules that determine the allowable separation, the management of the associated directional planning and surveying activities, and assurance and verification. The adoption of a particular minimum allowable separation rule, no matter how conservative, does not ensure an acceptably low probability of collision. Many other factors contribute, such as the level of compliance by office and rig personnel with collision avoidance procedures, and the completeness and correctness of the directional applications and databases. These factors are all connected.

Well collisions are relatively rare events, but anecdotes gathered by the technical section suggest that they occur more frequently than formal reports would indicate. The material is split into eight sections, each dealing with a critical element in the collision avoidance process. Examples are presented to highlight good implementation practice. This aligned approach will dispel some of the current confusion in the industry over well collision avoidance, improve efficiency when planning and executing wells, and build industry focus on the associated collision risks when drilling.

  • S. Sawaryn (Consultant)
2:00 pm Unconventionals

INTERSECT – Enabling Full Field Simulation Model of a tight reservoir

  • G. Walker (Repsol)

INTERSECT – Enabling Full Field Simulation Model of a tight reservoir

Unconventionals
Wednesday, September 13
2:00 pm

In the North Slope, Alaska (USA), Repsol has successfully used the INTERSECT simulator to achieve the finalization of a field development plan (FDP) with a very short deadline. The field is an offshore heterogeneous tight oil reservoir and Repsol’s current FDP requires the implementation of hydraulic fracture plans modeled by appropriate local grid refinements (LGR) around all the development wells. Repsol knew that in order to define a feasible FDP and to span the full range of associated uncertainties, they had to be able to do more simulations and faster. Initial simulations were run with the traditional simulators in serial mode and in parallel without providing much benefit. It was in this environment where INTERSECT simulations represented a step change in the work, because simulations with INTERSECT run in hours rather than in days – enabling Repsol to define an optimized FDP with a reduced turnaround time.

  • G. Walker (Repsol)
2:00 pm Production Operations

IO 2.0: Defining the digital blueprint for upstream

  • S. H. Mustapha (PETRONAS)

IO 2.0: Defining the digital blueprint for upstream

Production Operations
Wednesday, September 13
2:00 pm

PETRONAS IO was established in 2014 as an enterprise-wide program to standardize all digital oilfield implementations as well as enabling key elements of the Operational Excellence Management System (OEMS) globally. The IO program has spent the first three years focusing on production hydrocarbon management (PHM); physical asset management (PAM); and reservoir, wells, facilities management (RWFM); where solutions were developed on a standardized architecture and operationalized in collaborative working environments established at various levels. IO is the collaborative platform for the integration of people, process, and technology with the end goal to cover the entire upstream business.

A key aspect of the program has been to drive better understanding of the interrelationships of the organization’s operational elements and how asset teams need to be integrated. The goal was to ensure that people and processes were tightly aligned to enable optimal collaborative decision making and to build value through strategic linkages.

Physical collaboration environments—“IO centers”—were designed to employ a single standardized operating model that not only embodies the upstream OE themes, but also serves as a catalyst for change – guiding the cultural transformation required to embed collaboration, discipline mastery, and pride in performance as the standard way upstream personnel work.

To date, PETRONAS has recognized value on a scale of hundreds of millions of dollars. In the near term, it is expected that Integrated Activity Planning as well as the establishment of collaboration centers in each of the domestic regions will unlock additional value through proactive operations optimization and better collaboration.

Today, PETRONAS’ digitalization drive has prompted the need for IO to evolve to the next stage and shift from a process-driven approach to a value-driven approach to unlock value and opportunities at a faster pace. A value optimization approach requires end-to-end breadth of coverage from exploration to monetization focused on optimizing key business decision-making points throughout the value chain and elevating from descriptive optimization capability to advisory and prescriptive capability.

This paper will present how PETRONAS worked with Schlumberger, as its trusted advisor and primary solution partner, to develop and drive the strategy, vision, and execution of the future of PETRONAS IO: enabling cash generation activities and defining the digitalization blueprint for upstream.

  • S. H. Mustapha (PETRONAS)
2:00 pm Field Development Planning

Simulation-based Grid Size, Pseudocomponent and Injection Method Selection to Optimize EOR CO2 Injection: Pertamina Field Case Study

  • D. Yudo Novyanto (Pertamina)
2:00 pm Business Transformation

Transforming geoscience in BP

  • J. Moran (BP)

Transforming geoscience in BP

Business Transformation
Wednesday, September 13
2:00 pm

In 2012, BP embarked on an ambitious four-year programme targeted to deliver a boost in the productivity of the geoscience community across exploration and production, and in addition, reducing nonproductive time of new wells.

BP has more than a thousand geoscientists, driving major components of subsurface activity globally. Over time, through various BP mergers and acquisitions, we ended up with a diverse portfolio of tools, often with individual strengths but poorly integrated. This resulted in fragmentation and regionalization of common workflows and an inconsistent application of common standards.

To answer this challenge, the Chili Programme, as a combined Subsurface and IT undertaking, was created to build a globally consistent set of standard workflows and underpin these with a flexible and integrated technology platform. The combination of the two was key: we wanted to drive standardization in common activities to remove any tendency to reinvent the basics, whilst enabling the ingenuity of our regional geoscientists through the development of embedded BP technology.

Importantly, this common environment should lead to a better global understanding and control of our subsurface uncertainty and associated risks through an integrated view and improved confidence in our data.

The strategic long-term partnership we have formed with SIS to develop and deploy the Ocean, Studio/Petrel platform has been fundamental to the success we have seen.

This presentation focuses on our approach, the challenges and lessons we learned, the benefits we have started to see, and our potential future direction. In addition, we want to show how this has been the seed for driving modernization and digital change at pace into our organization.

  • J. Moran (BP)
2:00 pm Data and Analytics

Where are the Near Field Prospects? A model centric, cloud based and lean solution using Petrel

  • S. Tobias (NearFX)

Where are the Near Field Prospects? A model centric, cloud based and lean solution using Petrel

Data and Analytics
Wednesday, September 13
2:00 pm

Technological advancements over the last two decades have been breathtaking. We regularly apply Petrel based, model-centric workflows that are as powerful as they are comprehensive. And yet too many conventional exploration companies find themselves prospect-poor. Why is this, and what can be done?

Play-based exploration (PBE) is in use at many of these companies as the overriding paradigm with which to find new oil. The exploration process is broken down to its components, and various “Common Risk Segment” maps are combined to reframe the exploration challenge. The ultimate proof of its effectiveness is the play “creaming curve,” which shows how efficient the process is at finding the last commercial drop of oil. This is analogous to “lean manufacturing” principles in use by production groups, where drilling processes are continually optimized through the Shewhart cycle of plan–do–check–act. But there is a major difference. That difference is that a lean approach to drilling optimization refines a process that increases efficiency and reduces cost. In contrast, a successful PBE approach exhausts the play, and prospects disappear. The solution is to systematically find new plays, something discouraged by usual PBE risking schemes, which “punish” innovation by layering play risk on top of prospect risk.

There is a better way. Exhausted plays should be treated as broken systems, which are best solved through application of a lean “root cause analysis”. This is difficult to do with map-based PBE, but works well with a model-centric exploration approach. Models lend themselves nicely to simulations with which the innovative explorer can systematically find new play types by perturbing the individual components of a mature play. For example, two play-opening technologies that are not possible with a map-based approach are saturation height modeling combined and closed-loop seismic modeling.

This is a systems problem, and very multidisciplinary in nature. It is the rare business asset that has the bench depth needed to fully evaluate every broken near-field exploration system with available resources. The solution for international companies is to push the community workspace, or “Gemba”, to the Cloud, where Studio-assisted collaboration is more effective.

Taken together, a lean, model-centric, and cloud-based approach to near-field exploration is an option for globally dispersed companies that are looking for new ways to fill their portfolios.

  • S. Tobias (NearFX)
2:00 pm Subsurface Characterization (Room 1)

Latest development in Petrel Quantitative Interpretation module applied at Enfield Oil Field

  • K. Waters (Ikon Science)

Latest development in Petrel Quantitative Interpretation module applied at Enfield Oil Field

Subsurface Characterization (Room 1)
Wednesday, September 13
2:00 pm

Quantitative interpretation of subsurface seismic and well datasets has become a critical part of the vast majority of oil and gas projects. Quantitative interpretation, which involves (amongst other things) the application of rock physics analysis, seismic modelling, inversion, and reservoir property prediction are now considered a routine part of the subsurface workflow. Historically, however, many of the tools and applications available to end users required expert knowledge of the software and techniques. Over the last decade, there has been a significant drive to provide enabling technologies to the broader geoscience community, be they geologists, geophysicists, or engineers. Ikon Science have developed a number of new tools which are natively integrated into the Petrel QI module, providing Petrel users access, for the first time, to sophisticated seismic modelling, rock physics, and other analytic tools. The first of the features to be introduced was coloured inversion, allowing end users to rapidly transform seismic reflectivity data (an interface property) into pseudo-impedance cubes (layer-based property), delivering the data in a form which can be much more readily translated into the geological and engineering domains, facilitating integration across disciplines. Following introduction of coloured inversion, Ikon subsequently implemented their RokDoc 2D seismic modelling tool. RokDoc 2D seismic modelling provides a framework and application for cross-disciplinary working, allowing geophysicists to convey and communicate concepts relating to seismic resolution and detection; for geologists to sketch and test different geological concepts against real seismic data; and for geologists, geophysicists, and engineers to collaborate together to determine how best to integrate seismic, well log, and engineering data together into a robust 3D reservoir model. The latest new feature developed through this collaborative relationship is the anisotropy modelling function. Anisotropy can significantly impact a wide variety of geophysical data as well as have consequences for engineering studies e.g., borehole stability. It is therefore crucial that users can incorporate anisotropy analysis into their workflows in order to determine the potential impact on subsurface analysis and planning. This presentation will focus on the application of 2D modelling in a subsurface seismic interpretation workflow, where the end goal is to develop a seismic interpretation that honours, in a quantitative manner, both well log and seismic data and identifies the presence and location of oil and gas contacts. The workflow successfully combined well log data, legacy seismic inversion data, and seismic to delineate oil and gas reserves at Enfield, NWS Australia.

  • K. Waters (Ikon Science)
2:00 pm Subsurface Characterization (Room 2)

Amalgamated interpretation of high resolution seismic imaging, advanced wireline and production data into a coherent, dynamic reservoir description

  • B. Winkelman (Talos Energy LLC)

Amalgamated interpretation of high resolution seismic imaging, advanced wireline and production data into a coherent, dynamic reservoir description

Subsurface Characterization (Room 2)
Wednesday, September 13
2:00 pm

This case study refers to the Phoenix field located in United States waters, about 208 km (130 miles) south of the Louisiana coast in the Gulf of Mexico, Green Canyon Area. The water depth is approximately 2000 ft. The reservoirs are Pliocene-aged unconsolidated sands deposited by turbidite flows. Stratigraphically, these sands vary in character from clean, blocky sands to laminated sediment sequences. Discovered in 1998 by Chevron and BHP and originally called Typhoon and Boris respectively. Talos Energy is currently re-developing the field using proprietary reprocessed wide azimuth seismic (WAZ) data along with integrated log, fluid, and rock data acquired in several new wells.

Reservoir architecture and the size and reservoir quality of producing bodies remain a central concern particularly in deep water. In this case study, high-quality seismic imaging delineated the sand bodies and an intervening shale break between two stacked sands. Wireline evaluation in each well consisted of state-of-the-art formation sampling and pressure measurements, borehole imaging, and petrophysics. Reservoir fluid geodynamic analysis of wireline asphaltene gradient measurements indicate that each sand body is laterally connected and that the shale break could be a baffle as opposed to a seal. Formation geodynamics employing seismic analysis and wellbore imaging and petrophysical logging concludes the same. All other PVT and geochemical data are compatible with this assessment. The concurrence of high-resolution seismic imaging with advanced wireline for both formation and reservoir fluid geodynamics enables building robust Petrel models populated with the accurate fluid structures of the reservoir. History matching months of production matched most probable reservoir realizations, which are now the basis of reservoir simulation. Future exploration with step-out wells are being optimized with this powerful workflow.

This workflow integrates a comprehensive scientific foundation for fluid and formation characterization and modeling, from exploration to development phases. This allows placing the reservoir fluids and geological components within the context of the petroleum system model (big scale in space and time) and also in numerical reservoir simulation of the field (small scale in space and time). As part of this process, industry reference software such as Techlog, Petrel, and ECLIPSE are utilized to enable this workflow and decrease uncertainty in reservoir characterization and field development.

Note. From Talos Energy and Schlumberger.

  • B. Winkelman (Talos Energy LLC)
2:30 pm Well Construction

Multidisciplinary integrated drilling engineering and systems at Ecuador delivering solutions and high performance

  • C.F. Emanuele (Orion Energy)

Multidisciplinary integrated drilling engineering and systems at Ecuador delivering solutions and high performance

Well Construction
Wednesday, September 13
2:30 pm

Since September 2014, OFS reformulated the ECG PTEC / Drilling-TIC process to become a key differentiator in the eyes of the Ecuador oil industry, with the objective to improve performance in strategic projects/fields. SIS has been a key support on this achievement. This abstract shares the outcomes of this action that resulted in improvement in performance and solutions to Orion. Orion Energy (formerly known as Consortia Interpec and Maranon) is an international oil campaign in charge of blocks 52 and 54, both in the Oriente Basin, in Ecuador, since 2012. Schlumberger provided engineering and integrated services (IDS, D&M/GSS, BDT, M-I Swaco, Well Services, Wireline, and SIS as an integrator) on a rig contracted by Orion during the 2014/2015 campaign for 5 wells in 4 marginal fields: Ocano, Peña Blanca, Eno, and Ron; the 2015/2106 drilling campaign that drilled 6 wells at the same fields.

In the drilling campaign of 2015-2016: 6 wells (1 exploratory, I injector y 4 development). The complexity of the wells increased during the campaign.

The campaign finished with the Ocano-4 well (J modified, DDI = 5.85, inclination of 43 degrees, and displacement of 6040 ft.), with a final performance of 484.93 ft/day, drilling it in 23.4 days. With this well, we finished the Drilling Campaign above the expectations, delivering the well in advance of 5 days of the planed Tender time.

The first action from SIS in this integrated group was set and aligned with the vision: Integrate drilling systems of different segments to provide to our clients an optimum drilling engineering workflow that brings efficiency, reduces risks, and minimizes ILT and NPT. The strategy adopted to achieve that was:

  • Established Techlog as a unique platform to integrate all the segments/information—planning, execution, and lessons learned.
  • Adopted a unique platform as the data base: Techlog.
  • Added Drilling-Geomechanics support to the PTEC/Drilling-TIC team.
  • Defined the technical SIS work area and also established the integrated tasks and regular meetings.
  • Use RigHour to avoid ILT and accelerate the learning curve.
  • Implemented the Techlog RT and DPA modules to monitor the well performance.

After this project, Techlog and RigHour was implemented as part of the integrated solutions for internal and external clients in the Ecuador GeoMarket. These workflows and concepts are now being extended to another GeoMarket as CPG.

  • C.F. Emanuele (Orion Energy)
2:30 pm Unconventionals

Better understanding of hydraulic fracture geometry initiating from higher-stressed layers: A case study of stacked height model in a multi-horizontal well pad

  • K. Ueda (INPEX)

Better understanding of hydraulic fracture geometry initiating from higher-stressed layers: A case study of stacked height model in a multi-horizontal well pad

Unconventionals
Wednesday, September 13
2:30 pm

A prediction of fracture propagation horizontally as well as vertically in a higher-stress layer is important for understanding of not only the treated well stimulation design and drainage area but also inter-well acting behavior with a neighbor well’s hydraulic fractures initiating from lower-stress layers in multiwell pad. However, it is known that a pseudo-3D model (P3D) assumes fracture initiation from a lower-stress region to achieve reasonable propagation; thus, if fracture simulation is performed in a formation with a higher-stress layer, it causes too much height growth with much less lateral propagation. In a field application, our multi-stage fracturing case in the Horn River basin in Canada follows same challenge. To overcome it, in this case study, the stacked height growth model (SHG) is adopted in an unconventional fracture model (UFM) in Mangrove. In practice, how SHG is implemented with 3D stress shadow and multi-layer discrete fracture networks (MDFN) to create a reasonable fracture geometry in higher-stress layer in actual field is demonstrated.

Prior to simulating a fracture propagation, geomechanically initialized, a 3D mechanical earth model including multi-zone DFN sets was built with collaborative work done by geologists and engineers. On the basis of the prepared geo-cellular model, some past-stage stress shadow from a neighbor well’s stages has been taken into account with actual fracturing orders conducted by the field operation. As one of the guides to calibrate a fracture geometry, we also performed coupling simulation with VISAGE and generated synthetic microseismic events. The result was used to validate simulated fracture geometry has reasonable range, comparing simulated triggering events in the vicinity of hydraulic fracturing with actual events.

As the result of testing the fracture geometry induced by several combinations of the functions, SHG with finer layer had a good agreement with the observation of MS events, as well as fracture hit analysis performed in the pad before. Although computation is more expensive than P3D, some compromise, such as simpler DFN and coarse pump schedule, has been made so that the incremental computational disadvantage is mitigated. The outcome based on the iterative calibration process is finally used to simulate all stages fracturing conducted in the pad and used for further optimization study.

The approach shown in this paper is helpful for a completion engineer to optimize fracture spacing, well spacing, and how effective drainage area is created with in a multi-horizontal well pad targeting several formations.

  • K. Ueda (INPEX)
2:30 pm Production Operations

Integrated Approach to Waterflood Management

  • K. Albazarov (Maersk Oil)

Integrated Approach to Waterflood Management

Production Operations
Wednesday, September 13
2:30 pm

Abu Qir Petroleum Company (AQP), a major gas operator in Egypt, holds 100% of the exploration, development, and production rights of the Abu Qir concession in the Nile Delta offshore. With the goal of optimizing the development strategy, AQP sought to develop a model for estimating production rates, and consider the effect of the surface network. In addition to that, AQP wants to optimize the current production system to reach the full potential.

However, there were several barriers to developing a model-based approach: No reservoir pressure measurements had been taken in the past three years. Most wells had no valid productivity estimate; and shutting in wells for testing was not an option because downtime would incur production losses. As a result, AQP could not determine if wells were producing to their maximum potential. In the mature field of Abu Qir, reservoir pressure decline leads to the onset of liquid loading. Liquid loading occurs when the gas flow rate falls below a critical value, where the gas bubbles cannot lift liquids to surface. Such liquid buildups can cause the gas well to stop production. Due to reservoir depletion, the wellhead flowing pressures have declined to the point that compression will be required in the near future to maintain forecasted rates and maximize the reserves.

AQP and Schlumberger Integrated Solutions (SIS) developed an integrated field management workflow to solve the issues, above especially in the case of limited data availability. This project shows how different domains can cooperate to reach the best operating scenarios. We estimated the unknown reservoir parameters using the modern production data analysis methods in the Petrel PI platform. We used PIPESIM and the forecast from production data analysis to identify any current and future bottlenecks and optimize the production. We then used OLGA to identify and mitigate liquid loading in gas wells. Using the SIS tools, current production at AQPC was increased by 10%, at no cost. Losses in the reserves expected in the future are expected to be far less (estimated to be more than 60 billion standard cubic feet of gas) and forecasts are expected to be more realistic.

  • K. Albazarov (Maersk Oil)
2:30 pm Field Development Planning

Tengiz oilfield simulation techniques

  • A. Kassenov (SRI TPD KMG)

Tengiz oilfield simulation techniques

Field Development Planning
Wednesday, September 13
2:30 pm

Tengiz field is one of the largest oil fields in the world. The reservoir is an isolated carbonate structure of a big area and big thickness. High heterogeneity caused by complex heterogenic and structural history of the reservoir raises many uncertainties and makes characterization of the reservoir extremely complicated. This fact, along with big area and high hydrocarbon column of the reservoir may make some of reservoir characterization techniques less effective. The application of different permeability models was examined and compared through  its effect on history matching of bottom hole pressures of Tengiz field with modelling based on INTERSECT high-resolution reservoir simulator. Due to the large number of cells, the composite eight-component model, and a dual-porosity and permeability calculation of the hydrodynamic model in the simulator, the ECLIPSE 300 compositional simulator is not able to react to changes to adapt to development history in relation to the length of calculation time. In this concern, it uses the new reservoir simulator - INTERSECT. It can significantly reduce the time of calculation of hydrodynamic models up to 6 hours.

  • A. Kassenov (SRI TPD KMG)
2:30 pm Business Transformation

Maersk Oil: G&G software consolidation

  • J. W. Jeppesen (Maersk Oil)

Maersk Oil: G&G software consolidation

Business Transformation
Wednesday, September 13
2:30 pm

As part of a standardization focus driven by the intent of improving interoperability and effectiveness supporting the Cost Transformation initiative, Maersk Oil decided to standardize on a single platform for all their geological and geophysical (G&G) workflows. Their petrotechnical experts (PTE) used a mix of Petrel, legacy G&G software, and specialist tools. Maersk Oil decided to consolidate their G&G interpretation environment onto the SIS platform of Petrel supported by other specialist tools. This geology and geophysics consolidation (GGC) required a dedicated transition project in order to efficiently manage the change for the Maersk Oil legacy G&G software PTE community. To realize the cost benefit, the transition needed to be completed in a tight timeframe, ensuring that

  • Essential data and projects were transitioned
  • The PTE community transitioned to be operational in SIS platforms for interpretation analysis

Maersk Oil engaged the services of SIS to design and then to undertake the transition services. A focused assessment facilitated the transition design considering user training and support ensuring users are equipped with sufficient knowledge of the technology for their needs; workflow consolidation ensuring workflows are identified, and end results and constraints are understood to define newly defined workflows in the new technology; and project data migration supporting migration of data in the most efficient manner, while retaining a high level of data validation and quality assurance.

On design approval, the project proceeded with the data transition service formed of both onsite and remote resources from the SIS Pune hub, utilizing the SIS service, OpenWorks-to-Studio technology, and domain expertise to deliver the data from the legacy system into the SIS platforms.

In parallel with the data transition and quality control process, a customized training program was executed:

  • Customized training. This training was based on existing Petrel training material organized to better fit the needs of the end-user PTE community.
  • Specialist sessions: Once standard training was delivered, a sequence of workflow specialist one-to-one sessions was delivered as identified by the assessment.
  • Hyper-care SME support: Immediately after the training was held, dedicated hyper-care subject matter expert (SME) support was scheduled. These support resources followed the project execution flow.

With the successful achievement of the all the project goals, Maersk Oil has a continued focus to consolidate the technical applications environment, using a “follow the molecule” approach to ensure data consistency and integrity through workflows and data lifecycle to facilitate a more efficient and productive workforce.

  • J. W. Jeppesen (Maersk Oil)
2:30 pm Data and Analytics

BluCube - Inhouse Private Cloud Infrastructure

  • J. Ngondo (Schlumberger)

BluCube - Inhouse Private Cloud Infrastructure

Data and Analytics
Wednesday, September 13
2:30 pm

The growing worldwide demand for energy leads to hydrocarbon exploration in different depositional places and sizes, which, in turn, leads to high demand for efficient technology infrastructure that enables high level of studies and services. The challenge is often reflected in the process of combining several modern technologies, sharing computing power, storage, and internetworking several servers and client computers to establish such an infrastructure. “Cloud” is deemed the solution to this dilemma.

Cloud computing is a contemporary development in technology; however, the underlying concept dates back to 1960.  Although cloud is defined in slightly different ways, it is essentially a ready-to-run infrastructure pre-installed, pre-configured, and internetworked, enabling organizations to rapidly consume computing resource, rather than having to build and maintain computing infrastructures.

Sonangol E.P. (part of Sonangol Group) is a parastatal that oversees petroleum and natural gas production in Angola, with a corporate objective of achieving a production of at least 1.8 million barrels a day in the near future. To embrace the objective, a great responsibility has been placed on upstream activities. Sonangol EP is equipped with adequate upstream software and workflows. However, they lack computing hardware resources to run geology and geophysics (G&G) applications, which require intense graphics, storage, and high-performance computing. Constrained by the industry downturn, Sonangol E.P had to look into cost-effective efficient solutions to address the problem.

In partnership with Schlumberger (SIS Angola), Sonangol EP identified Schlumberger’s upstream applications private cloud infrastructure solution (BluCube) as an ample solution. BluCube is a bundled solution that includes converged infrastructure hardware, a cloud orchestration and provisioning software (“BluCube OS”), and associated services for deploying upstream applications in a cloud environment. Optimized for Schlumberger software, with the aptitude to host other vendor’s applications, makes BluCube a complete solution.

Succeeding BluCube deployment, there is much to be said in favor of the benefits it has earned Sonangol E.P; just to state a few

  • Reduced IT infrastructure total cost of ownership (TCO) by approximately 55%
  • Accelerated time to value and reduced IT complexity
  • Scalable, high-performance computing environment, equivalent to at least 40 high-end workstations
  • Modern and high-performance graphics rendering, efficient for G&G activities
  • Multi-tenancy and improved security
  • Easy maintenance and support of applications portfolio
  • Modern licensing model enabled (SaaS)

Besides meeting the objective, BluCube aligns with Sonangol E.P’s transformation goals, and it is a window towards other evolving IT technology trends.

  • J. Ngondo (Schlumberger)
2:30 pm Subsurface Characterization (Room 1)

A new approach to manage non-traditional structural model geometries applied to Lubina - Montanazo field, Spain: Powered by Volume Based Modeling algorithm in Petrel

  • R. M. Aguilar (Repsol)

A new approach to manage non-traditional structural model geometries applied to Lubina - Montanazo field, Spain: Powered by Volume Based Modeling algorithm in Petrel

Subsurface Characterization (Room 1)
Wednesday, September 13
2:30 pm

Traditional corner point gridding (CPG) has limitations when dealing with very complex structural geometries resulting in distorted cells. The lack of cell orthogonality can lead to issues like convergence complications during the simulation stage. Fault geometries in Y, X, and λ shapes together with carbonate deposit configurations in individual patches make the modeling process very challenging. In order to overcome these concerns, geomodelers might have to simplify their structural interpretations trying to avoid cell distortion as much as possible. Compared to other gridding methods, the implementation of the volume based modeling algorithm (VBM) in Petrel allows the construction of complex structural and stratigraphic models from a new direction, followed by the conversion to stair-step grids (SSG), which assures the proper three-dimensional cell configurations.

The main objectives of this study were: 1) to build a structural 3D grid capturing both the structural and stratigraphic complexities of a natural fractured carbonate field located offshore Spain, using VBM and SSG; 2) to reduce the time spent on building the structural grids compared to the CPG method; 3) to preserve volumetrics below 10% difference, between fine and up-scaled grids, from both CPG and SSG models; and 4) to obtain the most optimal grid to run dynamic simulations.

The followed methodology involved a previous input data conditioning which was the key to achieve a successful structural model. Due to the particular geometry of the area, in a “tepee” shape, the fault modeling step was crucial for the boundary definition in order to create a watertight model which constrained the horizons within the “tepee” structure. In addition, due to the stratigraphic complexity of the area, a logical stratigraphic relationship and proper horizons type definition were mandatory to be handled by the modeling algorithm. The final structural model was used as input to build a three-dimensional stair-step grid ready for property population.

Results show that stair-step grids reduce the cells distortion and capture the structural and stratigraphic complexities. The good orthogonality of the final 3D grid reduces the time needed by reservoir engineers to prepare the grid for dynamic simulations.

  • R. M. Aguilar (Repsol)
2:30 pm Subsurface Characterization (Room 2)

Experience of petrophysical and geomechanical analysis in naturally fractured Paleozoic reservoirs

  • K. Ezhov (NIS NTC)

Experience of petrophysical and geomechanical analysis in naturally fractured Paleozoic reservoirs

Subsurface Characterization (Room 2)
Wednesday, September 13
2:30 pm

Hydrocarbon reserves related to the basement have been discovered in all parts of the world: Latin America, North America, Asia, West Siberia, North Africa, and Europe. Such reservoirs include fractured or weathered metamorphic or magmatic rocks with complicated structure.

There is no doubt in the importance of such objects for the petroleum industry, but conventional approaches in exploration and development are not, partially or fully, applicable.

The interpretation of logging and petrophysical data obtained from complex reservoirs, in particular fractured metamorphic rocks, is a challenging task which is as relevant as evaluating the associated hydrocarbon recovery prospects. From the perspective of petrophysical study and forecast promising areas are evolving. The Paleozoic rock has three main types of cavitation: fractures, caverns, and the hollow zones of disintegrated rock. There is no clearly defined method for identifying pay zones and their properties using standard techniques.

Due to active and long tectonic history, geomechanical analysis should be an essential part of the work. Petrophysics alone can’t give such fruitful information as it can together with geomechanics: brittle, stiff intervals for fracturing or port placement, possible failures, and influence of stress anisotropy. The best producing intervals are most often related to fractured zones with specific elastic and mechanical properties.

The final model was built by integrating answers from high-tech tools such as formation imagers, X-dipole acoustic, and NMR measured by Schlumberger. In order to maximize the value of the data and get full understanding of this particular reservoir type, advanced processing techniques were applied.

Reservoir properties were estimated in Quanti.ELAN module, providing stochastic modeling and quantitative estimation of main metamorphic minerals in the formation. Results were calibrated on core analysis, porosity, grain density, XRD content, and results of NMR processing.

To quantify the secondary porosity, a method based on high-resolution electrical borehole image called PoroSpect was used, providing a porosity distribution. The presence of stress anisotropy was evaluated by processing the acoustics data and a geomechanical model was generated for wellbore and fracture stability analysis.

Such questions were analysed and fully or partially answered for the part of fractured basement: optimum intervals upon the effective thicknesses and brittleness analysis, secondary porosity determination, direction of stresses for horizontal wells, and rock typification in schists of different content. These topics and more will be presented in the course of our work.

  • K. Ezhov (NIS NTC)
3:00 pm Well Construction

How we protect our wells employing well barrier envelopes

  • T. Fjaagesund (Wellbarrier)

How we protect our wells employing well barrier envelopes

Well Construction
Wednesday, September 13
3:00 pm

Operating in the oil and gas industry has an element of risk when working with hydrocarbons under pressure. When constructing, operating, maintaining, working over or abandoning the wells, most people employ a two-barrier philosophy. But how do we do this?

If we are able to define two independent well barrier envelopes, we will allow incidents to happen without escalating into accidents. For certain well activities or for legacy wells, it may not always be possible to establish two independent well barrier envelopes. In those circumstances, it is even more important to understand what is in place in the wells to safeguard you and to know where you may be vulnerable so that you can take mitigating actions. How do we make people see this?

It then becomes important to convey to all stakeholders what physical well barriers are in place to protect us. For this reason, industry standards such as NORSOK, API, and ISO, together with corporate governing documents, recommend the use of Well Barrier Schematics. This gives us the principal starting point for how to safeguard our well activity.

Well Barrier Schematics are often made in Excel, PowerPoint, Visio or other drawing programs, with a wide array of quality and an individual touch. To convey well barrier descriptions in a consistent manner, easily understood by all stakeholders, there is a great benefit in having consistency in philosophy, graphics, and language.

The presentation will introduce the audience to a solid, unambiguous philosophy and preparation of well barrier schematics in a consistent, high-quality manner, easily understood by all stakeholders. The well barrier schematics are used to show how these could possibly have prevented some bad industry accidents through case examples. Furthermore, it will be shown how the well barrier schematics can be used as a valuable tool from the moment you start to plan your casing program, during construction, and through its life cycle until P&A of the well.

  • T. Fjaagesund (Wellbarrier)
3:00 pm Unconventionals

Volumes, Visualization, and Value: A case study of integration and operations in the Midland Basin

  • M. Davis (Encana)

Volumes, Visualization, and Value: A case study of integration and operations in the Midland Basin

Unconventionals
Wednesday, September 13
3:00 pm

The scale of the Midland Basin in West Texas, USA, owes its origins to a unique sequence of cratonic evolutionary forces that created geomechanically isolated, organic-rich-shale compartments producing narrow-ranged API gravities. It’s one of the most active and competitive oil plays in the world. The basin spans over 8,500 square miles with over 5,500 horizontals targeting more than thirteen formations over five-thousand vertical feet. Operators are actively stacking, chevroning, down-spacing, and pumping completion trials to maximize recovery and corporate value.

Encana Corporation demonstrates industry-leading well cost, completion optimization, cycle time improvement, and well productivity. A customized Petrel-based volumetric workflow has been created to map, track, integrate, analyze, evaluate, model, and predict well performance across the basin. The integrated approach to appraisal and execution allows for real-time evaluation of industry activity across the basin. The construct integrates every drilled lateral foot and pumped frac-stage with geological trends identifying key drivers to well performance, predicts activity trends, and evolves as new data is continuously integrated.

With four rigs spudding from a single surface location, and each rig drilling more than 5,000/day, Encana penetration rates can exceed 20,000 ft/day. Automated geosystems, including streaming directly into the Studio environment, allow for continual operational integration. Pad-scale operations drill within 15 ft of a landing zone while avoiding hundreds of pre-existing vertical penetrations. Encana has placed over 33 wells, 550,000 ft of pipe, and over 800 million pounds of sand from one surface location.

Within this Petrel environment, volumetric compartments are integrated with core, logs, 3D seismic, pressure observation wells, flowing bottomhole pressure data, field trials, microseismic, oil fingerprinting, and interference testing. The integration of geocellular property modelling with geomechanical and fracture observations forms the foundation of a Mangrove-INTERSECT-based modelling work flow used to simulate and iterate full-cycle development.

In conclusion, multilayer, high-density development necessitates an adaptable integrated geologic and operational tool capable tracking and visualizing development. This realization provides powerful insight into industry trends and seamless transparency of daily operations. Knowledge is critical to drive competitive advantage, industry-leading execution, inventory, and corporate growth projections.

  • M. Davis (Encana)
3:00 pm Production Operations

Comprehensive experiments and modelling reduce uncertainties in liquid management for the Tanzania Gas Project

  • H. T. Holm (Statoil)

Comprehensive experiments and modelling reduce uncertainties in liquid management for the Tanzania Gas Project

Production Operations
Wednesday, September 13
3:00 pm

The Tanzania Gas Project aims to exploit reserves located offshore from Tanzania in East Africa. The project faces challenges in the management of liquid content due to deep water, rough seabed terrain, long transport lines to shore, relatively steep inclinations, and very dry reservoir fluids. The narrow operational envelope associated with the water depth underlines the importance of accurate flow simulations for design and production. In addition, despite the low-liquid loading conditions, substantial liquid accumulation is expected in the upwardly -inclined sections of the pipeline for low production rates.

Several experimental campaigns were launched in SINTEF’s large-scale test facility at Tiller to reduce the uncertainty in the field development. A novel experimental “screening technique,” allowed for the sampling of an unprecedented number of flow rate combinations corresponding to the onset of liquid accumulation.

Diameter scaling was addressed by conducting similar experiments in 8- and 12-in. pipes at moderate inclinations. Froude number similarity was utilized for scale-up and to assess model predictions for field conditions. The data confirmed that the OLGA HD model captures the correct physics and allowed for fine tuning.

Additional low-liquid loading experiments where conducted in the 50-m-high vertical riser at Tiller. This provided the flow symmetry that allowed us to measure and develop a model for the apparent roughness and increased pressure drop associated with the presence of a thin liquid film between the gas and the pipe wall.

The data revealed interesting and unexpected phenomena for high water fractions. Nevertheless, the new film roughness model, which was based on dimensional analysis and simple but fundamental physics, was found to be in excellent agreement.

The updated OLGA HD model was applied in an uncertainty analysis for the Tanzania field, based on a large number of combinations of key input and flow model parameters sampled from estimated uncertainty distributions. Simulation results for gas production rate, minimum turndown point, etc. were determined as probability distributions. The effort to quantify and reduce uncertainty has been very successful. Statoil’s engagement with experimental researchers, model developers, and software suppliers greatly increased the understanding of the physics and diameter scaling of low-liquid loading flows, significantly reducing the uncertainty for gas condensate field developments.

  • H. T. Holm (Statoil)
3:00 pm Field Development Planning

Developing the full field simulation model of a fractured basement reservoir, West of Shetland, using INTERSECT

  • D. Bonter (Hurricane Energy)

Developing the full field simulation model of a fractured basement reservoir, West of Shetland, using INTERSECT

Field Development Planning
Wednesday, September 13
3:00 pm

Fractured basement is productive around the world, and; yet, despite offering significant resource potential, this reservoir has been underexplored and overlooked as a play within the UKCS. Hurricane is a forerunner within the industry in exploring this play and has successfully made two sizeable discoveries (Lancaster and Whirlwind, each ~200 MMboe 2C recoverable  resource) since 2009 in the UK West of Shetland province.

As a Type 1 naturally fractured reservoir (NFR), fractured basement has no effective matrix porosity or permeability; consequently, production efficiency relies entirely on a hydrodynamically connected natural fracture network. This results in a specific set of challenges which need to be accommodated as part of the workflow when building static and dynamic models of basement reservoirs. Hurricane has been using Schlumberger’s INTERSECT software to enable high-resolution, geological-scale simulation of the Lancaster Discovery, to history-match Hurricane’s successful 2014 horizontal appraisal well test, and investigate uncertainties leading toward full field development.

Hurricane presented, at the SIS Global Forum 2014 in Barcelona, on the work that had been performed utilising Schlumberger tools and software to develop a robust static model. The dynamic modelling was at an early stage, though the benefits of using INTERSECT were clearly demonstrated. This paper continues from that early work, to encompass the development of the full field pseudo-single porosity model that was used to achieve a good match to the well test data of horizontal well 205/21a-6, work that was performed in close collaboration with Schlumberger.

This first-phase was considered a ‘pseudo-single porosity’ model because the well test analysis of 205/21a-6 revealed (as Hurricane had suspected) that the Lancaster fractured basement reservoir exhibited dual-porosity behaviour. This dual porosity is caused by the interaction of different scales of fractures within the hydrodynamic fracture network – it remains a Type 1 NFR, with no effective matrix poroperm. For initial modelling, a simplified approach was desired. However, to honour the data and achieve a robust history match, Hurricane ensured the initial model utilised the dual-porosity interpretation in calculating the average parameters to be used in the geocellular grid. Ongoing work has focused on incorporating a realistic discrete fracture network (DFN) into the model and performing a full field simulation on an exceptionally large dual-porosity model using INTERSECT.

Establishing a suitable dynamic modelling workflow for Lancaster has beneficial implications not just for Hurricane’s remaining basement assets, but also for unlocking the basement play within the UKCS.

  • D. Bonter (Hurricane Energy)
3:00 pm Business Transformation

An integrated solution to tackle challenges in oil and gas production regulation in Mexico

  • U. Neri Flores (Comisión Nacional de Hidrocarburos)

An integrated solution to tackle challenges in oil and gas production regulation in Mexico

Business Transformation
Wednesday, September 13
3:00 pm

Mexico’s hydrocarbon exploration and production activities are undertaken in a broader and diverse environment containing onshore and offshore fields, both conventional and unconventional, with all types of hydrocarbons, from extra-heavy oil to light oil and from gas and condensate to dry gas fields. In addition, production operations are performed by multiple operating companies, including the state-owned company PEMEX, as a result of the comprehensive Energy Reform.

Regulation of these activities considering this widely varied production, technology, and operating conditions represents a challenge to provide a broad framework that is adjusted to both local and multinational operating companies while safeguarding the interest of the government in an attractive environment for investors.

The Integral System for Hydrocarbons Extraction (SIEH) allows the consistent and integrated flow of information to provide further support to the compliance-tracking of the regulatory processes related to reserves, field development plans, production measurement, and commercialization. In addition to the compliance-tracking in a timely and reliable manner, the SIEH enables multiple detailed technical analyses and integral KPIs associated to reserves evaluation, economic evaluation, fiscal regimes and contracts considerations, sensitivity analyses, and risk evaluation, which fosters the optimum development of the energy industry in the short, mid, and long term.

This ambitious solution is achieved by the interaction of SIS production and economics solutions combined in a seamless integration with the National Hydrocarbon’s Commission (CNH) hydrocarbon extraction regulation. The SIEH manages reporting levels from the technical and economics staff to the executive/commissioners level inside the CNH while also allowing for detailed reports directed to other government dependencies like the energy ministry or finance ministry and international organizations such as the IEA International Energy Agency.

SIEH represents the cornerstone to foster the oil and gas technical regulation in hydrocarbon extraction and help to promote the continuing success of the Mexican Energy Reform with the interaction of the CNH with the operating companies working in Mexico that took into consideration the experienced technical support from the SIS team combined with the high-level IT solutions.

Note. Authors: Ulises Neri Flores, CNH; Adelfo Torres Montiel and Christian Alan Ramirez, Schlumberger

  • U. Neri Flores (Comisión Nacional de Hidrocarburos)
3:00 pm Data and Analytics

Automated Rig & Drilling Data Management

  • B. Al-Khayat (Kuwait Oil Company)

Automated Rig & Drilling Data Management

Data and Analytics
Wednesday, September 13
3:00 pm

In order to meet KOC strategic production objectives, drilling activities ramped up during last two years with additional units of drilling rigs. Such challenging situation demanded extra efforts to ensure operational data completeness on time for downhole facilities’ components as well as drilling and workover activity details in the corporate database. The new state required a different approach to optimize the amount of work needed by drilling engineers to update such data into the corporate database. The need became evident for well-structured access of drilling operations and field development teams to high-quality and accurate data, effective workflows, and a consistent and frequently updated database. As an example, it was not possible to get a correct well schematic without an updated database with the right facility codes of all the downhole equipment. Currently drilling engineers are updating downhole facility and workover/drilling operation details in corporate database individually one component at a time using Oracle-based Finder forms.

As KOC endeavors for enhanced hydrocarbon recovery using high-end technologies like ResFlow inflow control devices (ICDs) and ResInject injection ICDs to help maintain uniform inflow and injection rates, respectively, across the entire length of the openhole completions, even in the presence of permeability variations and thief zones. ICD wells have a large number of ICD elements and, as well very time-consuming process to update ICD completion details into the corporate database.

To meet and beat such challenges, the IM Team developed a rig related and drilling data management solution with several modules, including:

  • Rig movement
  • Completion tally import
  • Workover and log of operations details Import
  • Data quality check

The system has been built in-house using .NET Technologies. It is integrated with OpenWells and FINDER and will support SeaBed (Prosource); work in progress involves migrating from FINDER to Prosource.

Key features of the newly deployed solution are that is more robust and time-saving, improves ease-of-use and gives a much better quality check, and has business rules implemented in it. The system has increased the data completeness and quality enhancement considerably. The estimated values to KOC through time saving is around 90% for data loading and almost 50% improvement in data quality respectively.

  • B. Al-Khayat (Kuwait Oil Company)
3:00 pm Subsurface Characterization (Room 1)

Implementation of an exploration workflow to characterize a low poro-perm gas-bearing prospect using rock physics depth trends to assist AVO classification in an integrated and versatile platform (Petrel)

  • J. Adrian (PertoSA)

Implementation of an exploration workflow to characterize a low poro-perm gas-bearing prospect using rock physics depth trends to assist AVO classification in an integrated and versatile platform (Petrel)

Subsurface Characterization (Room 1)
Wednesday, September 13
3:00 pm

An oil and gas company is not able to sustain over the time without creating value through its life cycle. In the last decades, PetroSA has been using sophisticated seismic and geological survey techniques to determine whether viable oil and gas reservoirs may exist and identify potential well locations for exploration drilling, by performing independent play-fairway analysis to evaluate the potential of the Syn-Rift II Valanginian Upper Shallow Marine (USM) Formation.

E-AT prospect, defined as a gas-bearing USM sands, has been identified as one of the most attractive USM prospects documented in the Block 9 potential/inventory in terms of geological risk and potential volumes. The main risks are associated to reservoir presence and quality. E-AT1 well was the only drilled in the area of interest, but planned to target a shallow reservoir. On the other hand, the few wells that target the same formation at a similar depth level are located far away from the interest structure.

This paper describes a methodology which seeks to de-risk this potentially large prospect in the USM by calculating the AVO response as a function of litho-pore fluid facies. Data from analogue wells and/or nearby areas are used to determine the distribution of Vp, Vs, and density for each likely facies defined, and empirical porosity-depth trend models are used to calibrate such data to the given depth of interest.

The different facies defined above are then combined with each other to cover all the realistic interface scenarios on the geological setting of interest. The interfaces AVO responses are computed using an approximation to the AVO Zoeppritz equation (Shuey), and AVO pdfs are then calculated from each interface scatter plot to predict the most likely litho-pore fluid facies from seismic (R,G) attributes.

AVO response as a function of litho-pore fluid showed a good separation between litho-facies (sand-shale) in the AVO attributes (R, G) dimension, but more subtle between fluid cases (sand-gas, sand-water), evidenced for the overlap. The methodology is particularly encouraging, especially in stages of exploration to predict litho-pore fluid properties, using seismic when none or few well data is available.

The workflow was possible to be implement thanks to the versatility and integration of the Petrel platform solution.

  • J. Adrian (PertoSA)
3:00 pm Subsurface Characterization (Room 2)

Modeling in Uncertainty: The Ghani Ed Dib Field Libya: Geomodeling case study

  • D. Middleton (Suncor Energy Inc.)

Modeling in Uncertainty: The Ghani Ed Dib Field Libya: Geomodeling case study

Subsurface Characterization (Room 2)
Wednesday, September 13
3:00 pm

The Libyan oil fields Ghani and Ed Dib are located in Concession 11 of the western Sirte Basin of Libya, a country containing the largest oil reserves in Africa. The reservoirs consist of portions of the Gir and Beda Formations, which are massive evaporite and carbonate successions that have produced oil beginning in 1969. The fields are operated by Harouge Oil Operations (HOO), a joint venture company owned by the Libyan National Oil Company and Suncor Energy of Canada.

A substantial understanding of the field was built with interpretation frameworks and structural models built using the Petrel geoscience interpretation and modeling software in Libya with Harouge in 2010–2011. This work built on the efforts of Libyan staff with extensive field knowledge and history, the specialized Suncor staff embedded in Harouge, to mentor and develop local expertise and skills, for the goal in creating detailed geo-cellular models to reflect a consistent model to accommodate previous work done by consultants and provide methods to iterate models at substantial milestones based upon new information gained from a continuous drilling campaign and sustained production. This work was continuing up to February 2011 and the unrest that subsequently lead to disruption in the country.

Post revolution, in the period 2013–2015, the Suncor Calgary-based Libya team began a multidisciplinary, large-scale field characterization process using the full Petrel seismic-to-simulation suite in order to create a current state reservoir model, to improve field understanding of more than 200 wells drilled over the evolution of the field, to develop active reservoir management practices that the integrated Petrel solution provides. The presentation will discuss the input, challenges, and static model that resulted from working collaboratively with the Libyan operator and the Suncor asset team to define and further develop this 4.5 Bbbl OOIP, where the volumetric uncertainty ranges from 3.1 to 6.0 Bbbl, and embed the iterative nature of reservoir modeling as an active part of the development cycle for an oilfield.

  • D. Middleton (Suncor Energy Inc.)
3:30 pm

Coffee Break

4:00 pm Well Construction

DrillPlan automation features enhance well planning at PRI Operating

  • M. Sims (PRI Operating)
4:00 pm Unconventionals

Integrated Multidisciplinary approach to Real Time Pore Pressure Prediction: 3D Earth Model in the Gulf of Mexico

  • F. Mosca (Murphy Oil Exploration & Production Company)

Integrated Multidisciplinary approach to Real Time Pore Pressure Prediction: 3D Earth Model in the Gulf of Mexico

Unconventionals
Wednesday, September 13
4:00 pm

Subsalt Gulf of Mexico deepwater wells routinely cost in excess of $100 million. The capability of a reliable pore pressure prediction can translate to considerable savings in terms of drilling costs. Traditional methods used to determine pore pressure are derived either from logs (Eaton’s method, Bower’s, etc.) and seismic (calibrated seismic velocities, acoustic impedance, etc.). However, no one method is commonly accepted as better than another; therefore, the capability of integrating all methods in a full 3D earth model, coupled to a three component stress behavior, can provide a higher degree of confidence for pore pressure prediction.

Pore pressure prediction using a 3D earth model for subsalt deepwater GOM projects requires integrating seismic attributes, geological information, well log data, drilling information, and drilling events. Recent developments allow coupling of classical pore pressure models with 3D stress models especially for fracture gradient prediction. This also allows for a correct understanding of the significant 3D effects in the vicinity of salt.

The first step of the workflow is to create and calibrate a regional model based on a set of regional maps with the main goal to provide the regional context. Accounting for possible regional faults, pressure relief points, mini basins distribution, and a full 3D salt restoration through time is able to provide the salt geometries related to salt withdrawal.

The second step is to create an AOI model using high-resolution structural and facies maps based on specific seismic character converted to net to gross. This refined model will then be used for pore pressure prediction at the prospect scale. The smaller AOI model, albeit at very high resolution, allowed a model to be run overnight so that pore pressure could be predicted ahead of the bit. Furthermore, LOT, LWD formation pressure data, and drilling events collected while drilling provided a very good calibration for the model.

A common element to both regional and AOI models is the capability to use a basin modeling software that allows full stress tensor and pressure analysis in three dimensions.

Finally, the predicted pore pressure and fracture gradient allows the drilling engineer to optimize well performance and reduce drilling costs. The integration of all the different disciplines and expertise through a 3D basin model resulted in the well to be drilled under budget and, most importantly, safely.

AUTHORS: Fausto Mosca1, Obren Djordjevic1, Thomas Hantschel2, Ian Hunter1, Tayo Akintokunbo3, Thorsten Joppen3, Ana Krueger1, Dave Phelps1, Stephanie Nyman1, Klaas Koster1, Michael Schupbach1, Kenneth Hampshire1, Andy MacGregor3 (1. Exploration, Murphy Oil Exploration & Production Company, Houston, TX, United States., 2. Schlumberger, Aachen, Germany, 3. Software Integrated Solutions (SIS) Schlumberger, Houston, TX, United States

  • F. Mosca (Murphy Oil Exploration & Production Company)
4:00 pm Production Operations

High integrity scalable data integration from self-declaring intelligent field assets enable digital transformation

  • A. Rentcome (Rockwell)
4:00 pm Field Development Planning

Numerical Simulation of Reservoir based on Equivalent Characterization of Small Scale Seepage Barriers

  • Z. Gao (Bohai Oilfield Research Institute, CNOOC Ltd.-Tianjin)
4:00 pm Business Transformation

Increased productivity by Integrated SIS software platforms at Turkish Petroleum

  • Y. O. Elis (Turkish Petroleum)

Increased productivity by Integrated SIS software platforms at Turkish Petroleum

Business Transformation
Wednesday, September 13
4:00 pm

  • Y. O. Elis (Turkish Petroleum)
4:00 pm Data and Analytics

The national data bank serving the Algerian energy sector strategy

  • F. Khamel (ALNAFT)

The national data bank serving the Algerian energy sector strategy

Data and Analytics
Wednesday, September 13
4:00 pm

In order to serve its governmental energy strategic objectives, Algeria, one of the major oil and gas producers in Africa, by its hydrocarbon agency ALNAFT, launched a project for the establishment of a national data bank, Banque de Données Nationale (BDN).

The BDN is designed to house all the data generated since the beginning of the hydrocarbon activities in the national mining domain, conveyed from disparate, undocumented, and heterogeneous sources. Moreover, generated data over several decades, do not obey a unified nomenclature. Those constraints were a challenge to collect, process, format, complete, and harmonize the data to finally load them into the BDN.

On the other hand, the second challenge faced by ALNAFT is related to the information management technologies. Indeed, the BDN must rely on an up-to-date and sustainable solution.

The Algerian BDN is meant not only to archive data, but also deliver a large range of services to internal and external users.

The BDN allows boosting of the country’s potential toward investors by regaining the true value of the shared, multidecade-produced data, improving by the same way the knowledge of the country’s subsurface potential.

Building such an ISO-certified, workflow-centric, with a robust data-standards basis data bank, is a unique experience. Today, the data bank is operated by ALNAFT for the promotion and valorization of the Algerian mining domain. The processes governing the BDN services (reception, processing, loading, checking, and delivery) are operational and mature.

In addition, the BDN aims to remain at the service of the energy sector strategy. To achieve this, the following axes are chased, and represent the future challenges:

  • Maintain and improve data quality to meet the BDN customer requirements
  • Apply international data management standards and best practices
  • Keep the information system up-to-date with cutting-edge technologies to ensure security, preservation, and improved access to data
  • Developing skills
  • Optimize the data workflows, from generation to hosting, in the BDN.

This paper discusses tailored strategies, tactics, and approaches to overcome the exposed challenges and the lessons learned while implementing an integrated digital tools ecosystem, fed with data from disparate sources.

  • F. Khamel (ALNAFT)
4:00 pm Subsurface Characterization (Room 1)

An update on the Volume Based Modelling project in Chevron

  • J. Vargas (Chevron)

An update on the Volume Based Modelling project in Chevron

Subsurface Characterization (Room 1)
Wednesday, September 13
4:00 pm

The static modeling of hydrocarbon reservoirs is broadly accepted to be a task that requires not only expertise, but a considerable amount of time.  The fact that information from different scales and domains is required to solve a complex geometrical problem creates the need to work “outside the box” and use non-traditional techniques.    This presentation describes the process used to build robust geological models in different depositions and structural environments using the Petrel volume-based modeling technique. The paper stresses how not only is the quality and heftiness of the methodology important, but the intimate knowledge of the math behind is needed to successfully complete a project.  Also it highlights critical advantages and limitations as well as recommends improvement based on Chevron experience.

 

  • J. Vargas (Chevron)
4:00 pm Subsurface Characterization (Room 2)

The Significance of the tectonic evolution on the in situ stresses in Rift Basins, GOS

  • Z. Elsisi (Gulf of Suez Petroleum Company)
  • W. Abdelghany (Gulf of Suez Petroleum Company)

The Significance of the tectonic evolution on the in situ stresses in Rift Basins, GOS

Subsurface Characterization (Room 2)
Wednesday, September 13
4:00 pm

This study focuses on pore pressure and fracture pressure prediction as a part of the wellbore stability (WBS) workflow employed for two different locations in a rift basin (peripheral and depocenter), with a successful case study on two wells that have been drilled based on these models.

The implication of this study is to reduce nonproductive time (NPT) associated with drilling the trouble zones, which may consume up to 40% of the drilling budget, this study plays an important role in minimizing the nonproductive time by choosing the proper depth for setting the casing seats based on the formation pore pressure and fracture gradient estimation.

The sedimentary pattern of the Gulf of Suez, Egypt, was controlled mainly by tectonic activities (subsidence and uplift) associated with relative changes of level. The synrift deposits showed a distinctive contrast in the thickness and lithology between the depocenter and peripheral basins. This contrast has a great impact on the overburden stress and the pore pressure regime.

An adequate calculation and prediction of the formation pore pressure and in situ stresses direction, magnitude and better understanding for the full geomechanical regime model of an oil field are very important prior to drilling any well. The basin modeling is an important, integral part of the well planning and formation evaluation process prior pore pressure prediction calculation.

The study assisted the well planner to predict the pore pressure for the upcoming wells to be drilled in the field, by finding out the relationship between the pressure regime model in relation to the geological setting of the area of interest.

Avoiding the environmental pollution, loss of reserves, and loss of human life or injuries resulting from abnormal pressure problems are benefits that will be achieved in this study.

The study passed through constructing a simple and effective tectonic framework, basin modeling, overburden stress, predicted and real-time pore pressure, and fracture modeling for Younes and Morgan fields.

  • Z. Elsisi (Gulf of Suez Petroleum Company)
  • W. Abdelghany (Gulf of Suez Petroleum Company)
4:30 pm Well Construction

Dynamic simulation of drilling fluid temperature to predict geothermal gradient

  • D. Kilgore (Apache)
4:30 pm Unconventionals

Full field thermal simulation of a giant extra-heavy oil field

  • R. Coll (Repsol)
4:30 pm Production Operations

Inventory management forecast based on automated processes using Avocet in the conditioning, storage and distribution facilities of Maritime Terminal Dos Bocas PEMEX

  • J. A. H. García (PEMEX)

Inventory management forecast based on automated processes using Avocet in the conditioning, storage and distribution facilities of Maritime Terminal Dos Bocas PEMEX

Production Operations
Wednesday, September 13
4:30 pm

Primary Logistics and Oil Treatment Department Southwest Marine Region (GTLP RMSO) is in charge of creating and coordinating the performance distribution programs and treatment of hydrocarbons received from PEMEX production assets in order to accomplish, with spec oil volumes, agreements to national and foreign clients. Maritime Terminal Dos Bocas (TMDB) is a processing facility, where around 880,000 BPD of heavy oil and 550,000 BPD of light oil is received for conditioning, storing, and distributing; therefore, inventory management forecast is critical for achieving contractual agreements and keep safe TMDB facilities.

Even though GTLP RMSO had a workflow to forecast the TMDB inventories, it was manual and limited because engineers had to capture all distribution programs for domestic consumption and exportation from files such as Excel, pdf, etc., sent by operations headquarters (GO). Inventories forecast horizon was maximum five days, and engineers spent almost five hours to do a projection for both products (heavy and light oil), besides the workflow did not have options to save several scenarios to compare them. Due to response for critical events was slow and without a scenario historical database, the result was not reliable for the decision-making process.

The challenge for this stage was to implement an automated process to acquire official information as tank inventories, production received and delivered by TMDB, and data from distribution programs files, which are also gotten automatically using Avocet as the core of solution. The business rules were implemented to create an inventory forecast for seven days automatically, and different scenarios can also be made for more than seven days, if it is required, to compare them and choose the best manner to manage the inventories. Results are deployed through management and operational reports, which can be accessed by the web. Additionally, this solution offers an inventory projection online for three days based on data acquired from a SCADA system and information simulated from OLGA.

The whole solution provides a scenario generated automatically every day at 8:15 hrs. Different scenarios can be created in less than 20 minutes for both products, which improves the response on critical events, improving the inventory management, considering compliance agreements with national and international clients, and keep safe the facilities on TMDB. Through reports and the dashboard, the clients are able to monitor inventory alerts as not TMDB capacity, to receive more crude. The decision-making process has improved, moving from reactive to proactive actions.

  • J. A. H. García (PEMEX)
4:30 pm Field Development Planning

INTERSECT and Petrel revolutionize the vision of reservoir simulation by making it possible to build and run a unique model of a giant field

  • S. Kaygorodov (LLC Gazpromneft STC)

INTERSECT and Petrel revolutionize the vision of reservoir simulation by making it possible to build and run a unique model of a giant field

Field Development Planning
Wednesday, September 13
4:30 pm

South-Priobskoe field (a part of the giant Priobskoe field, the third largest in Russia, and in the top-20 largest fields in the world) is a strategic Gazpromneft asset. It has been under development for more than 20 years. Currently the well count is represented by more than 3500 wells in the area currently being described by means of reservoir modeling. Due to low permeability, almost every well has been hydraulically fractured; therefore, the total number of hydraulic fracturing operations sums up to around 8000.

The field operational planning in different parts of the South-Priobskoe field includes decision support for drilling, completion, and hydraulic fracturing operations, as well as optimization of the reservoir production techniques. To achieve a sufficient history match of the hydrodynamic model on the entire field and to effectively use and update this model during further production forecasting at the field level, it was decided to run hydrodynamic simulations on the full field geological grid, thus omitting stages of upscaling and splitting the model into individual sectors, of which both may be very time consuming and at the same time lead to significant losses of the reservoir characterization quality. Rather it was considered to turn into practical value the use of modern high-performance computing systems for building, running, and maintaining the huge reservoir simulation model within moderate simulation time frames.

The total required number of grid cells for the hydrodynamic model of the South-Priobskoe field sums up to about 2 billion cells. Taking into account the complexity of the reservoir, number of wellbores, and hydraulic fracturing stages, this implied a significant challenge in terms of the RAM usage, parallel processing, resources utilization, and pre- and post-processing workflows.

The combined Petrel and INTERSECT solution was the only instrument capable of handling the full field hydrodynamic model of the South-Priobskoe field. It commingled the advantages of using the Petrel environment for model building, quality control, and actualization using the integrated seismic-to-simulation workflow, as well as the advanced parallelization algorithms implemented in INTERSECT. The achieved results in terms of the hardware requirements and simulation time were considered very successful because they ensured the possibility of this huge model application for decision support coherently with the regular activities of the Gazpromneft operational units; therefore proving that the selected approach is feasible from both an organizational and economical point of view.

This success and uniqueness naturally made Petrel/INTERSECT the benchmarking tool for assessing cluster systems performance.

  • S. Kaygorodov (LLC Gazpromneft STC)
4:30 pm Business Transformation

Implementation of exploration stage gate system and guideline in JX Nippon

  • Y. Ariga (JX Nippon)

Implementation of exploration stage gate system and guideline in JX Nippon

Business Transformation
Wednesday, September 13
4:30 pm

JX Nippon Oil and Gas Exploration, hereafter JX Nippon, has implemented an exploration-stage gate system and new exploration guidelines since April 2016. The purposes of the implementation are to standardize the decision process, establish alignment of risk and value assessment, and improve knowledge management.

JX Nippon has experienced several corporate mergers during the last 20 years. Such a diversified corporate culture is one of the strengths of the company however, we severely recognized a significant need to establish guidelines for technical evaluation works required from stakeholders. It is also important to ensure the right technical assessment at the right time, with the relevant level of technical rigor using standardized inputs into the corporate assurance process for decision making.

Our challenge is how to establish a standardized and effective process for exploration assessment and project validation. It is also important to instill the motivation and philosophy of the stage gate system into all stakeholders. To achieve this goal, we developed corporate standard guidelines for subsurface evaluations and project validations. SIS has provided valuable assistance for the process to establish these guidelines. We got several customized training courses by SIS experts to deepen our understanding and find issues to be solved. These are a great help to us all.

The guidelines provide the standard for project management, define milestones for the delivery of technical outcomes, set standards for integrity of subsurface technical deliverables, and emphasize timely collaboration, documentation, and knowledge management.

In March 2017 (1 year after implementation), we conducted an internal survey to follow up on the challenge of execution, level of adoption, and understanding of the guidelines. As the result, we recognized that we had to spend more time to instill review of the system and guidelines. Reflecting feedback from stakeholders, vital points to improve understanding are;

  1. Periodically explain concepts of the stage gate system and guidelines for stakeholders.
  2. Sharing advantage of guidelines and utilizing peer assist with stakeholders.
  3. Pay more attention to conduct peer-assists before peer reviews and assurance reviews to build consensus effectively.
  4. Further familiarize stakeholders with the guidelines and establish easier access when they need them as a reference.

We also recognized the importance of conducting periodic feedback. Throughout such follow up and improvement, JX Nippon continues making the effort to unify our culture and set a goal to create “JX Nippon’s way”.

  • Y. Ariga (JX Nippon)
4:30 pm Data and Analytics

5 become 1: Building a foundation that enables corporate digitalization

  • I. Barron (RoQC)
4:30 pm Subsurface Characterization (Room 1)

Don’t Panic – GeoX Implementation at Wintershall

  • K. Schmidt (Wintershall Holding GmbH)
4:30 pm Subsurface Characterization (Room 2)

The key reservoir characterization technology in strategic discovery of a giant ancient carbonate gas field in Sichuan Basin, China

  • Z. Z. Luzi (PetroChina)

The key reservoir characterization technology in strategic discovery of a giant ancient carbonate gas field in Sichuan Basin, China

Subsurface Characterization (Room 2)
Wednesday, September 13
4:30 pm

In 2011, a giant gas field was discovered in the Sinian and Cambrian strata in Moxi–Gaoshiti region, central Sichuan paleo-uplift, with the geological reserves reaching more than one trillion cubic meters. The main gas-bearing layers include Deng 2 Member and Deng 4 Member of the Sinian Dengying Formation and the Cambrian Longwangmiao Formation. Based on a brief review of the exploration history of a large gas province in central Sichuan paleo-uplift, the paper systematically describes the formation conditions and petroleum accumulation patterns of the giant gas field and points out the large ancient uplift background, huge net of hydrocarbon supply system, large-scale particle shoal reservoirs, and regional reservoir-cap combinations that are important material conditions for the formation of the giant gas field. In view of the huge depth, high temperature, high pressure, low porosity, low permeability, and some other complex formation conditions such as high formation water salinity, high content of pyrobitumen, and high content of silicon, a lot of efforts have been put into the research on key reservoir characterization technology, and a series of accomplishments have been achieved, which work well in the exploration and development of gas in Sichuan Basin. The Sinian and Cambrian strata in the Sichuan Basin have a great potential for petroleum exploration.

This paper discusses a novel combination of the Schlumberger wireline scanner family technology such as LithoScanner, CMR, ADT, FMI, MDT, etc. and SIS software for the reservoir characterization of tight carbonate formation in Sichuan basin. The technologies powered by Schlumberger’s Techlog and Petrel increase the efficiency and lower the uncertainty during decision making.

Case studies are presented from carbonate reservoirs in the Sichuan basin. A robust and comprehensive petrophysical description of lithology, porosity, pore geometry, permeability, rock types, fractures and sonic anisotropy is presented, by utilizing Schlumberger’s latest technologies on Techlog and Petrel. A new understanding of carbonate reservoir heterogeneity is established. The synthetic curve that incorporates several petrophysical properties turns out to be a good prediction of production.

  • Z. Z. Luzi (PetroChina)
5:00 pm Well Construction

Real-time data integration enables enhanced workflows for better drilling performance and drilling events avoidance

  • O. O. Ramirez Amayo (PEMEX)

Real-time data integration enables enhanced workflows for better drilling performance and drilling events avoidance

Well Construction
Wednesday, September 13
5:00 pm

Real-time drilling monitoring workflows targeting the reduction of nonproductive time (NPT) and the improvement of the drilling performance is a vital part within the Pemex strategy to improve drilling score cards.

In alignment with this corporate strategy, the Tsimin Xux asset, in September 2014, assigned to Schlumberger Integrated Solutions (SIS) and Geoservices (GSS) the task to run the Paraiso Centro Inteligente de Pozos (CIP) - Wells Intelligent Center – operating 24/7 throughout the year.

The CIP combines Pemex and Schlumberger technologies, processes, and resources united to deliver unique workflows designed to face the challenges that exist while drilling the Tsimin Xux wells.

Challenges:

  • Subsurface uncertainties, mainly represented in the inexact mapping of mudstone intercalations, becoming zones of high risk for stuck pipe/sidetracks.
  • Inaccurate Paleocene entry identification has been a continuous source of drilling problems.
  • Less than expected drilling performance poses a severe drilling challenge for the operator and service companies.

The solution comes divided in two parts:

  • Data acquisition, transmission, and visualization: SIS provides the technologies and services to enable safe data collection and transmission from the rig site to the CIP. Data acquisition is done by the rig site data hub (RSHD). The RSDH is equipped to collect surface and downhole data, which is then transmitted through the Pemex network to the InterACT server located within the Pemex premises.
  • Drilling optimization: SIS and GSS drilling specialists use the performance tool kit (PTK) to analyze the surface and downhole data residing in InterACT to apply advanced drilling workflows aimed to overcome the existing field challenges, optimize performance by proactively generating alerts, and make operating recommendations to drill faster within the well’s technical limits.

Conclusions:

After a year of continuous operation, the Paraiso CIP has been systematically delivering preventive alerts to reduce the occurrence of NPT events:

  • Well 1: early detection of mudstone intercalations helped prevent stuck pipe events that, under normal conditions, could have been the source of over-costs from at least 8–10 days of NPT.
  • Wells 2 and 3: where advanced data analysis and correlations allow specialists to produce results to detect the on-time Paleocene entry. Missing this important geological feature can potentially put at high-risk the well from reaching total depth, with the production delay consequences that come with it.

Currently, the technologies RigHour and Drillbench are being considered by the CIP to continue the constant improvement of operations in the Tsimin Xux asset.

  • O. O. Ramirez Amayo (PEMEX)
5:00 pm Unconventionals

Integrated Modeling to Improve Well Performance in the Permian Basin

  • K. Wilson (Chevron)

Integrated Modeling to Improve Well Performance in the Permian Basin

Unconventionals
Wednesday, September 13
5:00 pm

Chevron drilled its first exploration well in the Avalon Shale of the Delaware Basin in 2012 and collected an extensive dataset including core, a full log suite with borehole images, PVT samples, downhole gauges, and a 3D seismic survey. This dataset was integrated through the Petrel platform and Mangrove workflow to inform key decision variables on future development such as well spacing, target landing zone, and completion design. First, a geomodel was constructed using core-calibrated log properties and seismic structure. Next, hydraulic fracture geometry was generated using field pumping data and a discrete fracture network (DFN) generated from borehole image logs.

Using the predicted hydraulic fracture geometry, a production history match was then performed on more than two years of data from the appraisal well. Key history-matching variables were unpropped fracture behavior and relative permeability functions. With the calibrated production model in hand, a wide range of sensitivity cases were used to analyze well spacing, landing zone, and completion design.

The project learnings include the interdependency of well spacing and completion design, the impact of proppant settling on near-wellbore conductivity and optimal landing zone, and the expected reservoir drainage volume from future development wells. After this study, subsequent development wells implemented changes to the landing zone as well as to the completion design. A lookback of production results from the development wells indicate improved performance compared to the appraisal well and in line with the uplift predicted in the modeling study. These results have improved confidence in the workflow and led to additional studies to optimize reservoir targets in the Permian Basin.

  • K. Wilson (Chevron)
5:00 pm Production Operations

Liwan Production Management System (PMS): First OLGA Online solution in South China Sea

  • T. Wang (Husky Oil)

Liwan Production Management System (PMS): First OLGA Online solution in South China Sea

Production Operations
Wednesday, September 13
5:00 pm

Liwan 3-1 is the first deepwater gas field developed in the South China Sea and is also the first deepwater project operated by Husky. The gas field development consists mainly of 10 production wells, 2 subsea manifolds, and a pipeline end manifold (PLEM). All production fluids commingle at the PLEM, which is located at around 1400 m water depth, and are then transported to the central platform (CEP) in 200 m of water via 2 80km pipelines.

The transportation of production fluids over this distance and gradient involves numerous operational challenges, which have the potential to disrupt the smooth operation of the subsea production system. In order to manage the product transportation infrastructure most efficiently, Husky contracted Schlumberger to implement a production management system (PMS) for the Liwan asset.

The PMS is a software application designed to assist the operators, reservoir, production, and flow assurance teams to manage the production from the wells and pipelines. The PMS provides real-time, online monitoring, forecasting, and offline training capabilities. A detailed OLGA model is central to the PMS application and has been developed completely based on the Liwan 3-1 system architecture. The PMS has been configured with 10 functional advisors which can provide operational guidance to operations from different perspectives, such as virtual metering, hydrate and slug management, and corrosion and erosion monitoring. The scenario and look-ahead (LAM) functionality can be used to perform planning and forecasting simulations using the real-time operating conditions as a starting point. All production data and simulation data can be accessed via the PMS historical database, which enables data backup and analysis.

The accuracy, reliability, and robustness of the PMS have been demonstrated by actual operations since this program entered operation almost 3 years ago. In this period, the PMS has brought value not only to Husky Deepwater Operations but also to our onshore partner, in terms of production allocation. Close collaboration between Schlumberger and Husky Energy ensures continuous improvement of the application in line with evolving operational needs.

This presentation will provide a general introduction on the Liwan 3-1 gas field and will mainly focus on the PMS application and its functionalities, as well as lessons learned. Special attention will be given to PMS Virtual Flow Metering Function which has saved Husky Operations more than USD 10 million as of now.

  • T. Wang (Husky Oil)
5:00 pm Field Development Planning

An integrated modeling approach to assess asset’s current and future production scenarios

  • A. Nugrahanto (Saka Indonesia Pangkah Ltd.)

An integrated modeling approach to assess asset’s current and future production scenarios

Field Development Planning
Wednesday, September 13
5:00 pm

Field development planning for an asset requires close collaboration and interaction between different domains and departments, to reduce any potential uncertainties and to better manage any possible risks within the studied asset. In realizing the importance, a fully integrated asset model has been developed to represent the entire Ujung Pangkah asset, which is to be studied in this project as one unit with no virtual boundaries and with full account of system constraints; this consequently enables cross-department interactions and assembles a fully integrated asset team to work towards a common goal.

The aim of the project was to evaluate the current operating envelope, quantify the benefit of different possible production scenarios, and use it to validate the planned developments for Ujung Pangkah field, with an integrated asset approach to identify any possible constraints in the system when the separator pressure was reduced. The developed integrated asset model consists of models of reservoir, wells, production network, and downstream process facilities (offshore and onshore facilities). The study has demonstrated any components of the production network system and its topside operating conditions could impose constraints on the production deliverability and ultimately the overall reservoir recovery factor. It also presented a scenario study with inclusion of gas lift distribution system to enable a more comprehensive analysis of the field-wide production optimization.

Current production philosophy has been modelled and matched with historical production. This represents a base case for the field. In the study, several selected production pressure system scenarios have been simulated. It was observed that by lowering the system pressure by 25% and 50% will increase recovery 6% and 8%, respectively, in 10 years of production. The modeling result also identified a potential future surface facilities bottleneck at those evaluated scenarios. This information is valuable for company to make decisions and evaluate the overall economic of those scenarios.

  • A. Nugrahanto (Saka Indonesia Pangkah Ltd.)
5:00 pm Business Transformation

Implementation of a portfolio management platform

  • A. Al-Hamad (Kuwait Oil Company)
  • T. Al-Adwani (Kuwait Oil Company)

Implementation of a portfolio management platform

Business Transformation
Wednesday, September 13
5:00 pm

KOC Exploration’s current exploration portfolio is quite sizable, covering 20+ plays (many underexplored with significant yet-to-be-found resources) and hundreds of undrilled prospects and a number of significant discoveries under delineation/appraisal. KOC Exploration teams were conducting play & prospect assessments with different processes in different assets and no common, centrally managed, database for plays and prospects data. KOC is using GeoX in exploration assessments and decided to standardize GeoX utilization across all plays, prospects, and discoveries across different divisions.

To increase visibility of the entire portfolio and gain efficiency in prioritizing prospects, KOC management decided to implement a systematic, fact-based process to rank plays, to focus efforts on high-value prospects and to quickly understand the implications of changes to strategic direction or environment. Our approach focused on developing a strategic prioritization framework: key strategic drivers were identified, weighted, and then defined as play/prospect properties in GeoX. This enabled every play & prospect to be scored against the strategic drivers relevant to it, highlighting the alignment of each play & prospect to the current exploration strategy.

Database management of all plays & prospects is done through GeoX, customized to support the technical processes. Staff training was key to ensure a standardized data entry throughout all asset teams, as well as consistent analysis and play & prospect assessments. Efficient dashboards and tools have been set-up to ensure that the right discussions are taken, through efficient data analysis and means to slice-and-dice data in multiple different ways depending on the decisions to be taken, e.g.:

  • Probability of different portfolio mixes meeting short- and long-term reserve addition targets 
  • Economic value of portfolio by region / maturity / play
  • Prioritize plays and prospects to focus resources, to maximize strategic / economic value
  • Trade-off decisions between prospects, analyzing risked resources vs. strategic alignment or economic value vs. resource additions
  • Rig allocation (and optimization) and prioritization of ready-to-drill prospects 

Ultimately, the main value came from giving the Exploration Management team easy and flexible access to all the information they required to make the best decisions on where to allocate resources to across the exploration portfolio. This was enabled through the advanced analytical functions of GeoX together with some tableau dashboards populated directly from data extracted from GeoX (thereby retaining GeoX as the single source of portfolio data).

Authors: Yousef Al-Salali (Presenter) and Talal Al-Adwani

Co-authors: Muhammad Al-Ajmi, Haifa Al-Bader, Abdulaziz Sajer, Sunil Singh, Waleed Morsy, Abdullah Al-Hamad, and Hanan Al-Kandari, Kuwait Oil Company, Kuwait

  • A. Al-Hamad (Kuwait Oil Company)
  • T. Al-Adwani (Kuwait Oil Company)
5:00 pm Data and Analytics

ETAP’s database management enhanced through ProSource solution

  • I. Bouyahya (ETAP)

ETAP’s database management enhanced through ProSource solution

Data and Analytics
Wednesday, September 13
5:00 pm

ETAP, the Tunisian National Oil Company, supervises exploration activities and directly participates in all hydrocarbon-related operations. As per the E&P rules, every operator in Tunisia should provide ETAP with different types of petrotechnical data.

As such, ETAP is playing the role of the Tunisia E&P patrimony safeguard; its responsibility is to acquire, secure, store, and manage all the data. In order to achieve these objectives, a relational database was deployed in early 2000, based on old Schlumberger technologies such as AssetDB, LogDB, and SeisDB software, and the Finder. As these platforms became unintuitive and difficult to manage due to the many separate databases in place, some inconsistencies of stored data, and lack of defined workflows and collaboration between teams, the status of ETAP’s database was a compelling event to migrate the existing systems to an up-to-date technology and set up real data management policies. This migration would help in making the database play its role when it comes to the efficient management of data and to provide easy and fast access to these stored data.

ETAP is currently initiating a pilot project that aims to set a National Data Repository that would enhance the overall rate on investment of the database and establish better data management practices.

By offering an end-to-end solution that ensures the connectivity of all the data stored under the advanced Seabed data model and enabling management of data on different administrative levels, the SIS ProSource E&P helped in solving most of the ETAP database issues.

The delivery of this database project started with a series of assessments on the existing data stored in the different databases as well as interviews done with all key users. Based on the assessment reports and findings, both ETAP and Schlumberger SIS agreed on a project methodology to follow for the upgrade and migration to the ProSource system. The project was successfully delivered in six months. ETAP’s database staff benefited from the ProSource training sessions and took advantage of the SIS team of consultants presence to conduct key, enlightening discussions.

Upon successful completion of the migration to the ProSource system solution, the database staff started setting out well-defined and domain-specific workflows and designing their learning and development programs, as well as establishing and applying standardization procedures. Teams were thus restructured, and intensive data loading activity, quality checking, and validation started in a collaborative working environment.

Adhering to higher levels of data management policies throughout the scalable ProSource system solution has so far helped to increase trust in the quality of stored data, which, in turn, is going to remedy the lack of collaboration among the company departments.

  • I. Bouyahya (ETAP)
5:00 pm Subsurface Characterization (Room 1)

Seismic volume visualization in Petrel applied towards detection of Zechstein depositional environments: Case study from the northern edge of the Southern Permian Basin, UK Southern North Sea

  • R. Gras (Oranje-Nassau Energie)

Seismic volume visualization in Petrel applied towards detection of Zechstein depositional environments: Case study from the northern edge of the Southern Permian Basin, UK Southern North Sea

Subsurface Characterization (Room 1)
Wednesday, September 13
5:00 pm

Seismic volume visualization techniques within Petrel were applied to a 3D seismic data set located near the northern edge of the Southern Permian Basin, the prolific gas basin of the Southern North Sea. Techniques applied were RGB blending with a range of input volumes, edge detection volumes, seismic ‘covisualisation’ (or mixing) of an extensive range of input attribute volumes. The area of interest occupies a basin-margin position during the deposition of the Permian Zechstein Formation, which is characterized by carbonates, dolomites, anhydrites, and halite. As a result of the analysis, a range of depositional geometries were illuminated; these include shoals, channels, and carbonate buildups, with a varied shapes and geometries within the Z3 cycle. Correlation with nearby exploration wells allows the depositional geometries to be classified within the classic Zechstein depositional cycles (Z1 to Z4). The resulting sedimentary facies interpretations have critical implications for the reservoir potential of the area studied.

Coauthors: Mark Geluk, Benjamin Medvedev, and Berend Vrouwe

  • R. Gras (Oranje-Nassau Energie)
5:00 pm Subsurface Characterization (Room 2)

Sonatrach: Beyond standard petrophysical interpretation

  • H. Chadouli (Sonatrach)

Sonatrach: Beyond standard petrophysical interpretation

Subsurface Characterization (Room 2)
Wednesday, September 13
5:00 pm

The exploration business becomes more complex each day, and technologies used by petrotechnical experts continue to evolve at an unexpected rate. In addition, and more especially on the wellbore domain, the multiple measurements and techniques have increased for a better understanding of the reservoirs characteristics.

Sonatrach, as many companies, used to acquire the standard petrophysics analysis and complement the work by investing in new acquisition methods by which more reservoir information could be extracted. However, because of the big investment, the need to optimize the data is crucial. In order for Sonatrach to capitalize on this investment, Techlog was one of the solutions that was chosen as an answer to the new measurement technology.

Sonatrach Exploration, in particular, had big challenges, of which the first one was the workflow non-uniformity and collaboration, as working on different locations and different domains, our workflows were subdivided into domains specificities, without “physical” bridges between components.

The second challenge was the confidence on the multimineral interpretation. We used GeoFrame as main platform and needed to know if Techlog will be more productive on this domain.

The last challenge was to fully extract the information from the new acquisition tool, which should answer to the reservoir challenges as shale, tight, and carbonate reservoirs. Techlog offered the opportunity to do this as it is capable of

  • Extracting capillary pressure from NMR measurement
  • Processing the Sonic Scanner for anisotropy
  • Realizing a sedimentology study from imaging log
  • Creating 1D mechanical earth model for drilling

Therefore, Sonatrach and Schlumberger decided to launch an initiative with solutions adapted to our main challenges. That was achieved by setting key components:

  • Mentoring the new engineers on Techlog
    • Engineers from Sonatrach were working closely with Schlumberger experts, so as to transfer the competency on the Techlog platform
    • Building the foundation of the reporting in Sonatrach department by creating templates
    • Getting familiar with the fundamental petrophysical modules and then to be prepared for the advanced petrophysical evaluation.
  • Organizing workshops on different wellbore measurement processing and interpretation
    • Creating a thematic workshop to extract the full knowledge from the measurement:
      • Formation pressure
      • Wellbore imaging
      • Nuclear magnetic resonance for capillary pressure
      • Anisotropy analysis from acoustic tools
  • Implementation of the advanced techniques, and SIS putting in place the necessary access to the technology of Techlog

Accordingly, Sonatrach, in cooperation with Schlumberger, is able to design and implement new technologies and hence new solutions to achieve the planned objectives:

  1. Enable an efficient collaborative environment
  2. Get the best result from multimineral interpretation (Quanti.Elan) and be more productive by the interactivity, prepared template, and the ease of use
  3. Go beyond the classical petrophysical interpretation with the advanced modules

The complementarity of “Software Integrated Solutions”, group of workflow and technological consultants, has maximized the capabilities to build a collaborative working environment and to design new way of working by extending the wellbore workflow.

Eventually, and following this success, it is worth today extending these solutions and dedicated workflows to other disciplines, i.e, wellsite geologist, etc.

  • H. Chadouli (Sonatrach)

9:00

Patrick Pouyanné, CEO TOTAL SA

9:30

Jamal Abdul Aziz Jaafar, CEO Kuwait Oil Company

10:00

Vicki Hollub, CEO Occidental Petroleum Corporation

10:30 am

Coffee Break

11:10

Bernard Looney, Chief Executive, Upstream BP

11:40

Joseph C. (Joe) Geagea, EVP Technology, Projects & Services Chevron

12:10

Gavin Rennick, SIS President Schlumberger

12:45 pm

Lunch

1:45 pm

Exhibition Open

2:00 pm

Technical Program, Executive Drilling Program, Executive Exploration Program, Executive Meetings

3:30 pm

Coffee Break

5:30 pm

Close

7:00 pm

Buses depart for dinner at Bateaux Parisiens

2:00 pm Well Construction

An innovative well planning workflow using DrillPlan

  • D. Carson (Petro-HUNT, LLC)
2:00 pm Unconventionals

Exploiting the cloud to operationalize the Kinetix Shale “Model to Design” workflow

  • S. Geetan (EP Energy)

Exploiting the cloud to operationalize the Kinetix Shale “Model to Design” workflow

Unconventionals
Thursday, September 14
2:00 pm

The importance of customizing completion designs to specific well/pad conditions is paramount. The challenging price environment makes the traditional learning approach through multiple field trials unacceptable. At EP Energy Corporation, the practice is to optimize the frac design for every well in digital space prior to ordering materials to location. To meet the timeframe dictated by field operation schedules, a step change in how we design frac treatments was needed. Exploiting the cloud met the challenge.

The production performance from shale wells depends greatly on the effectiveness of the hydraulic fracturing treatments. Reservoir heterogeneity and changing stresses resulting from offsetting well injection and depletion cycles makes obsolete the “one size fits all” rule for frac design. Fit for purpose frac designs require multiple scenario testing for each well/pad configuration requiring multi-well models, which often take days to run. The 2016 Mangrove workflow could not efficiently keep up with the timeframe for field operations decision making. The Kinetix Shale modeling capability with cloud access is instrumental to operationalizing the workflow for faster turnaround of model results and sensitivity testing.

Sensitivity testing of the Kinetix Shale hydraulic fracturing model plays an important role in expanding the solution space of the calibrated model. It expands the range of numerical assessments and allows for the evaluation of new and untested designs in digital space. Digital trials using multiple scenarios with different combinations of engineering parameters require significant compute time and must be done in a field-mandated timeframe to influence pumping operations. Sensitivity modeling on the Cloud enables more timely results, which allows for better decision making.

In this presentation, we will demonstrate how Kinetix Shale on the Cloud was used to “operationalize” completion designs for a pad with drilled but uncompleted (DUC) wells. The “neighborhood” is first conditioned by using Kinetix Shale to calibrate parent well by replicating as-pumped frac schedules and history matching post frac production using INTERSECT. After resetting the stress field, the DUC wells are stimulated using the latest-generation frac designs in Kinetix Shale. After calibration, the optimization workflow begins. The goal here is to assess in digital space the resulting production prediction for alternative frac designs. Economic models are then fed the sensitivity results where a cost benefit assessment is made. The “model-to-design” journey combines our understanding of physical causality from the Kinetix Shale model with the power of Cloud computing which leads to an increased confidence in fracture treatment design decisions and does so in a timeframe that meets the operation schedules.

Note: Authors: Richard M. MacDonald and Steve Isaac Geetan, EP Energy Corp; Timothy Pope and Jean-Paul Dessap, Schlumberger

  • S. Geetan (EP Energy)
2:00 pm Production Operations

Successful deployment of Avocet allows Gazprom International Germany the consolidation of global production data from different producing assets in the North Sea, Asia and Africa

  • M. Zuehlke (Gazprom)

Successful deployment of Avocet allows Gazprom International Germany the consolidation of global production data from different producing assets in the North Sea, Asia and Africa

Production Operations
Thursday, September 14
2:00 pm

Starting deployment in 2015, at present the Avocet system is up and running in Gazprom International (GPI) Germany Berlin offices and consolidates production data (daily and monthly) from different producing assets in the UK (Saltfleetby and Wingate fields), Asia (Schachpachty field in Uzbekistan) and Africa (Libya).

Avocet has been setup as a production data collection hub (PDC) for GPI Germany.

  • Data are coming into Avocet from Excel files generated in the assets via automated data loading processes.
  • In addition to production (including delivery and sales data, where available), also well head measurements are being loaded such as WHP, WHT, BHP, BHP, casing pressure and tubing pressure (although not all parameters are available for all assets).
  • No allocation is performed within GPI Germany’s Avocet implementation; instead, raw and already allocated data received for the various assets are consolidated and rolled passed up the organization hierarchy (automated process).

Reports (based on a predefined Gazprom template):

  • A production report was created for the Wingate asset as part of the original scope, which was consequently used to create an additional report.
  • The additional Libya production report was also created by Schlumberger as an extended scope of work.

Avocet PDC extension with WINZ Assets in 2017 and beyond.

  • As GPI Germany has taken 50% share in Wintershall Noordzee (WINZ), GPI Germany would like to expand the existing Avocet PDC to also include the WINZ assets.
  • The WINZ extension will include:
    • Extension of the PDC with about 40 fields, with their associated wells, platforms, and organizational hierarchy
    • Loading of historical data
    • Loading of available production data received on a daily\weekly\monthly basis
    • Creation of one WINZ asset production report.

Authors: Alexej Kurkow, Gazprom International Germany, Ben Turk, Schlumberger, and Martin Zühlke Gazprom International Germany

  • M. Zuehlke (Gazprom)
2:00 pm Field Development Planning

Flexible integrated asset models for deep water developments

  • A. Cominelli (Eni)

Flexible integrated asset models for deep water developments

Field Development Planning
Thursday, September 14
2:00 pm

In the oil and gas industry, planning and updating field development requires complex, integrated asset models (IAMs), where reservoir simulators, network simulators and, ultimately, process simulators work together, coordinated by an orchestrator program. IAMs are developed to answer a wide range of questions posed by reservoir engineering, petroleum engineering, production engineering, and flow assurance. Providing proper answers to all these different disciplines in a cost-effective manner throughout, an integrated modelling logic demands flexibility in the choice of the simulation solutions. Reservoirs may be simulated using ECLIPSE or INTERSECT, while the network simulators can be a simple but effective table lookup-based tools like the ECLIPSE Network Solver or a sophisticated, general-purpose program like GAP, depending on whether the driver is reservoir engineering or petroleum/production engineering.

In this paper, we present how a flexible IAM was developed for a key deepwater asset to provide a solution that could be adapted to meet reservoir engineering and petroleum/production engineering needs by using INTERSECT simulator modularity. INTERSECT represents reservoir simulation as an integration between two processes, the field manager (FM) and the reservoir simulator (IX), the former one providing boundary conditions to the latter one.

The asset at hand consists of seven reservoirs and, in the preparation of the field development package, these reservoirs were simulated using ECLIPSE while two IAMs were built using different solution for networks – namely Gap and the ECLIPSE Network Solver. Drilling of development wells and early production data collected in one of the key reservoirs motivated the construction of a detailed model where heterogeneity could be captured. INTERSECT was used to run common-scale simulation in a cost-efficient manner, while the other reservoirs were still effectively simulated using ECLIPSE and this motivated the development of a new IAM where different simulators could be used.

The new IAM was developed following the INTERSECT simulation logic, where FM steers both network and reservoir models, using adaptors for the different modules. The process was staged: first, a simplified development based on water flooding only, was included in the IAM strategy; then, the full asset development, with water–alternating-gas- injection implementation, was incorporated.

This solution ultimately allows a much larger flexibility with respect to previous ones because the asset team can use the same tool and switch easily from GAP to ENS depending on the needs of the simulation. Notably, FM allows the use of highly sophisticated python scripts to custom field management logic well beyond what was available before.

This IAM is currently used in the asset team to study new development options and the impact of reservoir history match updates on the full field performance, using ENS to maximize computational efficiency and results stability, while GAP networks are used to evaluate top-side facility updates and to provide input to process and flow assurance engineers.

  • A. Cominelli (Eni)
2:00 pm Business Transformation

Benefits from a global Petrel E&P software platform and Studio deployment within Nexen

  • G. Urquhart (Nexen Energy)

Benefits from a global Petrel E&P software platform and Studio deployment within Nexen

Business Transformation
Thursday, September 14
2:00 pm

Nexen, a wholly owned subsidiary of CNOOC Limited, discovers and develops energy resources in some of the world’s most significant basins – including the UK North Sea, offshore West Africa, the United States of America, and western Canada. In 2014, Nexen made the decision to adopt the Petrel E&P software platform as their platform for geoscience workflows and interpretations and Studio for the data management, knowledge capture, and asset team collaboration across the asset teams. Nexen globally deployed Petrel and Studio throughout 2015. This global adoption of a Single Global Geoscience Platform for Geology, Geophysics, and Reservoir Engineering have resulted in:

  • Organizational efficiencies (enabling the mobility of skilled G&G resources across priority projects) and operational effectiveness (through the creation of a single repository of G&G data with the ability to integrate/extend the G&G model into well planning, reservoir simulation, well placement, and drilling)
  • Simplified business process, data management, data integration, and the associated ITS support organization thus reducing the cost of ownership
  • Improved efficiency/performance of the existing workflows
  • Improved interdisciplinary integration/collaboration from G&G to modeling and simulation
  • Improved data integrity and accessibility (all data in one place)
  • Reduction in the number of G&G software packages used within the team by replacing them with a single-vendor solution (Petrel and Studio)

 

  • G. Urquhart (Nexen Energy)
2:00 pm Data and Analytics

Petrel data management using Studio database

  • M. Pelton (ExxonMobil)

Petrel data management using Studio database

Data and Analytics
Thursday, September 14
2:00 pm

ExxonMobil has used Petrel in the upstream business environment for several years and was experiencing common data management issues, including inability to find definitive data, duplication of data, incomplete data, and disk space problems. We selected Studio to help mitigate these problems as well as to enhance the G&G’s efficiency and effectiveness.

We ran successful pilots with two asset teams. One team had a large number of wells and the other team had significant seismic volumes. The pilot teams and the asset teams spent much effort grooming, consolidating, and organizing the data before loading into Studio. Our deployment method leveraged tight linkage between the business asset teams and the pilot teams, so that the definitive data and work processes were mapped into new processes using Studio with Petrel.

Both benefits and limitations were identified during the pilots. Benefits included data integrity, increased efficiency, and improved user collaboration, allowing the business to more quickly achieve better-informed decisions. Some limitations were identified as well: difficulties with survey expansion, user-defined attributes, and well tops versioning. The IT organization also took steps to better define some of the data management roles as well as grow the hardware and systems environment to support the deployment and use of Studio to additional asset teams. As a result, both asset teams elected to keep Studio in the environment because the benefits received outweighed the limitations encountered.

Studio has matured significantly over the subsequent years through collaboration between ExxonMobil and Schlumberger to improve the product. These improvements made Studio a more complete data management solution. We have deployed Studio to many of our affiliates across the organization and continue to see the benefits and efficiencies that enable quicker response to business needs. Some examples are: farm-in opportunities and the ability to quickly assess new areas. We are discovering more benefits each day as we gain more experience with Studio.

As Schlumberger continues to evolve the Studio offerings, we will continue, as I am sure others do, to work with them to influence that evolution. As always, it takes concentrated, cooperative effort of the Business and IT organizations for us to fully deploy and achieve business benefits from Studio use.

Authors: ExxonMobil Exploration Company (Div. ExxonMobil Corporation), Kristen Poteet, ExxonMobil Technical Computing Company, Scott Robinson,

Presenter: Joe Dischinger, Geoscience Technology Portfolio Manager, ExxonMobil Exploration Company (Div. ExxonMobil Corporation)

  • M. Pelton (ExxonMobil)
2:00 pm Subsurface Characterization (Room 1)

Visualizing Change over Time in Assets from Space: Analytics linking the Surface to the Subsurface

  • D. Humphreville (DigitalGlobe)
2:00 pm Subsurface Characterization (Room 2)

Capturing the complex architecture, using the Volume Based Modeling (VBM) workflow, provides new insights into the dynamic performance of the North Rankin field, a producing giant gas field on Australia’s NW Shelf

  • A. Kaiko (Woodside)

Capturing the complex architecture, using the Volume Based Modeling (VBM) workflow, provides new insights into the dynamic performance of the North Rankin field, a producing giant gas field on Australia’s NW Shelf

Subsurface Characterization (Room 2)
Thursday, September 14
2:00 pm

The giant North Rankin gas field has been supplying Australia’s North-West Shelf Project since 1984 and is expected to continue for many years. The field comprises an elevated horst block containing complex internal faulting, with styles including top truncation and multiple stacked antithetic and crossing faults. The application of the VBM and stair-step gridding workflow has enabled this complex architect, identified from intensive seismic interpretation, to be more fully captured providing new insights and understanding of into the dynamic behaviour of the field.

Dynamic simulation of this model, with appropriate global fault transmissibility applied, provided an excellent history match to field performance at the first attempt. Significantly, an alternative model based on simplified structure gave significantly inferior match.

With ongoing dynamic calibration of the model, including varying aquifer size and connectivity, history matching to reservoir pressure data and contact movement has led to a refinement of the field’s gas initially in place and the range of forward production profiles. Furthermore, new insights and understanding of field performance have arisen concerning the GWC movement noted in some wells, the potential for field compartmentalization, the potential for regional aquifer support, and the significant pressure difference encountered in an offset well.

The application of the VBM workflow has allowed a new level of complexity to be modelled especially in sparse data areas, while minimizing the level of seismic interpretation required. The resultant insights and understanding of the field’s dynamic performance has assisted in our future field management planning and production strategies.

Note. Authors: Alex Kaiko, Peter Thomas, Alexis Whelan, Jai Louis, Grant Fryer and Tanita Prater

(Woodside Energy Ltd)

  • A. Kaiko (Woodside)
2:30 pm Well Construction

LUMEN: Geosteering Look Ahead goes live with data integration in Petrel

  • F. Arata (Eni)

LUMEN: Geosteering Look Ahead goes live with data integration in Petrel

Well Construction
Thursday, September 14
2:30 pm

Structural estimation capability ahead of the bit is evolving with innovative combinations while drilling of borehole and surface data in real time. A pioneering workflow has been developed to recalibrate the reservoir structure via integration of surface seismic with synthetic seismic, derived from logging-while-drilling (LWD) GeoSphere measurements.

Modern LWD services have nowadays reached a significant depth of investigation capability, expanding the horizons of geosteering applications. GeoSphere, the ultradeep azimuthal electromagnetic (EM) technology, provides real-time information on a cylinder of rock around the wellbore, up to 200-feet in diameter. This technology enables a new opportunity to update the pre-drill 3D geomodel with the measured local volume of information. Synthetic seismic, derived from GeoSphere measurements, is compared with real seismic data, using non-rigid matching to quantify the depth mismatch. The estimated displacement is then applied to the real seismic and to the pre-drill Petrel model repository (i.e., identified reservoir horizons, faults, and geobodies) to predict the structural setting of the reservoir ahead of the bit. It is possible to iterate through these steps using an automated process while geosteering.

The workflow was tested on post-drill data acquired on an Eni well, recently geosteered within an oil reservoir consisting of fluvial and deltaic deposits of Triassic age. The automated interpretation tools, integrated on the seismic interpretation software, allowed building a pre-drill Petrel model in two-weeks’ time. The model provided a base for the creation of the geosteering roadmap considering the structural features potentially present along the planned trajectory. The real-time simulation lasted two days in a play back mode, focusing on the assessment and validation of the workflow. Each process iteration took few minutes to provide results, validated in parallel with LWD available data. The calibration provided a robust dip and structure estimation and additionally the confirmation of fluid contact position, as identified in the pre-drill analysis.

The workflow unlocked extra look-ahead possibilities for optimal geosteering, and proved to be able to provide robust information 150 m, on average, ahead of the bit. The presence of structural discontinuities was successfully validated within 30 m measured depth from the predicted position. This novel approach is a step further toward the possibility of providing accurate reservoir updates ahead of the bit, and so forth to improve well placement operations while updating Petrel models in real time.

  • F. Arata (Eni)
2:30 pm Unconventionals

Planning for the future: Delivering a robust development plan for the Mississippian Lime in the STACK play, Oklahoma, USA

  • M. Ellis (Alta Mesa)

Planning for the future: Delivering a robust development plan for the Mississippian Lime in the STACK play, Oklahoma, USA

Unconventionals
Thursday, September 14
2:30 pm

The STACK play in Oklahoma comprises multiple complex reservoir levels including the Oswego, Manning, Mississippian Lime, Woodford, and Hunton. This presentation focuses on the study of Mississippian Lime reservoir and addresses significant production variability that has been observed from wells drilled in the area. The business case was to define an NPV-driven horizontal field development plan for future operations in an area of interest comprising multiple operating units.

A subsurface study was carried out using a risk-reward business concept, whereby Schlumberger risked a significant portion of consulting fees for a bonus, which will be awarded if a >10% production uplift is achieved from a basket of 10 wells to be drilled subsequent to the conclusion of the study and utilizing recommendations from it. Schlumberger deployed a technical team for six months comprised of petro-technical experts from their SIS and IPS organizations, utilizing state-of-the-art software tools and workflows, and representing multiple disciplines, working collaboratively and closely with Alta Mesa’s technical experts and management team. This “skin in the game” risk-reward approach alongside a commitment from both Alta Mesa and Schlumberger personnel to be open and transparent during regularly scheduled (weekly) communication sessions led to a successfully executed and extremely collaborative study.

The team incorporated multiple data scales (core, log, seismic, operational, and production history) in a 3D model to understand the production drivers for the Mississippian Lime. This included investigation of the role of structure, natural fracturing, lithological/rock variability, and coupling to stress profiles, hydraulic fracture propagation, and sensitivity of operational fracturing parameters. Ultimately, an understanding of production controls and their variation over the area of interest concluded with recommendations for lateral landing point at multiple depths and number of wells by section to mitigate well interference between wells during production. Through integration of data types across scales and disciplines, we were able to address key unknowns such as OIP in matrix versus fractures, hydraulic fracture network coverage, effective drainage area around wells and recommended down-spacing for maximizing NPV economic production section by section.

The results have already been utilized in the selection of a number of high-graded drill locations for the bonus wells chosen by Alta Mesa and Schlumberger. Well-spacing tests in sections have been updated and alternate landing points are being targeted.

Note. Authors: Mike E. Ellis and Hal Chappelle, Alta Mesa Holdings

  • M. Ellis (Alta Mesa)
2:30 pm Production Operations

Infrastructure meets High Performance Computing Simulation Technology – Sonangol EP’s Experience

  • V. Santos (Sonangol)
2:30 pm Field Development Planning

Using Advanced Petrel-Intersect Workflows for Infill Well Planning under Uncertainty

  • A. Rath (OMV)
2:30 pm Business Transformation

Extending Petrel Workflow capability with Blueback Toolbox Python Tool (in Collaboration with Cegal Ltd)

  • I. Demaerschalk (Tullow Oil Plc)

Extending Petrel Workflow capability with Blueback Toolbox Python Tool (in Collaboration with Cegal Ltd)

Business Transformation
Thursday, September 14
2:30 pm

The Petrel workflow editor is one of the most powerful tools within the Petrel suite of tools.  At its most basic, you can record a sequential set of processes or actions or repeat a simple action numerous times without user interaction; at its most powerful, it creates additional functionality not available in native Petrel.  However

  • Calculator workflow scripting can result in extended workarounds due to limitations
  • Dealing with each grid index sequentially can form a time barrier
  • The Petrel calculator language does not extend far enough in certain cases

In collaboration with Tullow Oil, Cegal Ltd have created a tool that is a halfway house between simple workflow automation and a dedicated plugin: the Blueback Toolbox Python tool.This new commercially available tool:

  • Makes certain workflows easier to construct, edit, and read
  • Gives significant performance gains using Python, in particular for array handling scripts
  • Draws on extensive additional open source Python libraries, which will prevent the need to reinvent the wheel.

In comparison with writing Ocean plug-ins for Petrel, the tool will allow Petrel-users to focus on the algorithm and geoscience rather than worry about memory management, data transfer, etc.  Combining Python and native Petrel within ‘master workflows’ yields a very powerful workflow environment in Petrel. 

Examples to demonstrate the above will be presented including:

  • A workflow to overcome the limitations of simulation faults by adding stair-stepped barriers to a simulation grid. Developing this functionality has aided history matching and has helped prolong the life of existing grids. It also allows for simpler grids to be built and handles problematic faults in a different way.
  • A workflow to classify sands according to their thickness using log data, allowing for more in-depth data analysis, options to model sands with different parameters pending on their thickness, and automation of perforations to be added based on sand thickness and the net-to-gross of the interval they are in.

  • I. Demaerschalk (Tullow Oil Plc)
2:30 pm Data and Analytics

Role of integrated technology in preparation for Uganda’s first licensing round

  • B. Ocitti (Ministry of Energy and Mineral Development, Uganda)

Role of integrated technology in preparation for Uganda’s first licensing round

Data and Analytics
Thursday, September 14
2:30 pm

In February 2015, the Republic of Uganda announced the first licensing round of its history. Schlumberger SIS had the honor to be selected to provide the Petroleum Exploration, Development and Production Department (PEDPD) in the Ministry of Energy and Mineral Development with an integrated suite of technology and services for data rooms, geological and value prospect assessment, and licensing round marketing services.

Uganda’s first licensing round for petroleum exploration, development and production targets six (6) blocks; Mvule, Karuka-Taitai, Ngassa, Kanywataba, Turaco and Ngaji. The Petrel Studio database and collaborative environment was used to organize and safely provide access to the block data for investors’ visualization and interpretation. The solution will be demonstrated during the presentation. In order to further understand petroleum potential of the blocks, PEPD economists and geoscientists were trained on GeoX which, combined with Petrel prospect delineation capabilities, provided the software platform for stochastic geological and value assessment of the prospects in the blocks.

The Honorable Minister of Energy and Mineral Development, Uganda, and her team conducted the licensing round announcement roadshow in London before a large audience of investors. In addition to the licensing round announcement, they presented the prospectivity of the proposed blocks from a geological and economical attractiveness point of views, Regulatory and Institutional frameworks and data availability. The roadshow success was possible using Schlumberger’s marketing tools campaign.

This presentation will expose the geographical and geological context of the licensed blocks, on and offshore Lake Albert. The solution will be demonstrated during the presentation where PEPD will share the Petrel-GeoX experience and the key achievements during the licensing round preparations.

  • B. Ocitti (Ministry of Energy and Mineral Development, Uganda)
2:30 pm Subsurface Characterization (Room 1)

Structural restoration of the Jurassic section at Kra Al-Maru and Riksah structures: An IGEOSS utilization case study in Kuwait

  • H. Salem (Kuwait Oil Company)

Structural restoration of the Jurassic section at Kra Al-Maru and Riksah structures: An IGEOSS utilization case study in Kuwait

Subsurface Characterization (Room 1)
Thursday, September 14
2:30 pm

Jurassic reservoirs in the Kra Al-Maru and Riksah areas consists of two reservoir units—from base up as a heterogeneously interbedded limestone, dolomite and anhydrite succeeded by an upper homogeneous succession composed mainly of tight limestone, carbonaceous shale, and kerogen. Both the units are capped by a thick cyclic salt and anhydrite sequences. The rock succession has a simple stratigraphic configuration; however, the tectonic events that this area has undergone are complex.

In an attempt to capture major tectonic variables associated within the study area during the Jurassic, structural restoration by backstripping and finite-element modeling technologies. The reason behind doing such analysis is to understand the kinematics and the drivers behind negative inversion along the major dextral strike-slip fault system.

Two representative cross-sections have been utilized for the restoration. One cross-section along WNW-ESE and the other along NE-SW has been used. The cross-sections are perpendicular and parallel to the major strike-slip faults, so that the variations in fault kinematics are adequately captured.

The structural restoration analysis reveals that during the Lower-Jurassic the study area is subjected to extension, followed by two stages of compression and a stage of strike-slip movement in the Upper-Jurassic. During Neocomian, earlier deposited salts are compacted, consequently leading to lateral salt movement and thrusting. It is therefore inferred that local tectonics has its own fingerprint in the area which is superimposed by regional plate-wide tectonic stresses

The analysis has proven to be vital for prospect evaluation. The study shows that the Riksah structure has been subjected to a series of uplift and subsidence events, leading to maximum strain and stress concentration in the area. Such concentrations would result in congenial natural fracture system and help upgrading the prospectivity of Jurassic units in the area and adjoining exploratory areas as well.

  • H. Salem (Kuwait Oil Company)
2:30 pm Subsurface Characterization (Room 2)

Petrel forward stratigraphic modeling: An amplified understanding for the next frontiers of geological knowledge

  • E. Tavares (Pertobras)

Petrel forward stratigraphic modeling: An amplified understanding for the next frontiers of geological knowledge

Subsurface Characterization (Room 2)
Thursday, September 14
2:30 pm

Facing 2016 and Petrobras’ worldwide geological scenarios, it is clear that the technologies that helped us get here in terms of hydrocarbon exploration and production may not be sufficient to address new challenges and conquer the next frontiers of geological knowledge and understanding.

In terms of geological modeling, the classical geostatistical methods have demonstrated to be very robust but may be not enough to provide the tools to solve even more complex or detailed scenarios. The study and analysis of available data can be greatly enriched by approaches that represent more closely the sedimentary and diagenetic processes of rocks, empowered by uncertainty analysis based on physical methods.

These methods, called forward stratigraphic modeling, have begun to appear as a viable alternative for the representation of both siliciclastic and carbonate reservoirs and are promising a great contribution toward the efficiency of exploration and production plans.
The stratigraphic forward modeling method in Petrel is based on the principles of conservation of mass and energy to produce chemical and physical processes responsible for the filling of sedimentary basins, such as erosion, transport, deposition, and production of sediments.
In both scenarios, siliciclastic and carbonate scenarios, a model’s parameterization involves temporal variations of base level, sea level, which when associated to a subsidence model and carbonate factory’s efficiency, determines the distribution of sediments in appropriate environments.

Paleobathymetric maps are also important to define different facies associations. Other parameters, such as the action of waves or dissolution of material, cement, and matrix, can also have a major impact on the sedimentary register.

The main result of stratigraphic forward modeling is a geological model with a scale of millions of years that represents the bathymetry variation and, consequently, different energy levels that have characterized a given geologic history. Also, properties of occurrence probability for each facies considered are obtained.
These results may potentially be used as input in subsequent probabilistic modeling, or as training images for multipoint statistical methodologies, or be converted into seismic cubes for a better understanding of possible seismic flexions that a given reservoir would produce.

In this presentation, we will show a case study from Brazil’s eastern margin, comprising Aptian aged, composed mainly by in situ microbial and reworked sediments. Playing through time the evolution of the model, it is possible to analyze base level variations, sediment proportions, and sediment residence time in each diagenetic zone. A clear and undeniable advantage of this methodology is to ensure that stratigraphic and sedimentological attributes responsible for reservoir heterogeneities are represented in the generated models, thereby giving opportunity for an unprecedented level of geological knowledge and conceptual scenarios. This clearly translates into a greater and deeper oil field awareness and into a decision-making process supported by an amplified understanding.

 

  • E. Tavares (Pertobras)
3:00 pm Well Construction

Optimizing drilling efficiency and performance benchmarking through multi-disciplinary work plan for Kuwait’s Real-Time Drilling Decision Center

  • S. Al-Ghunaim (Kuwait Oil Company)

Optimizing drilling efficiency and performance benchmarking through multi-disciplinary work plan for Kuwait’s Real-Time Drilling Decision Center

Well Construction
Thursday, September 14
3:00 pm

Kuwait Oil Company (KOC) continues to pursue an aggressive E&P campaign, aligned with organizational objectives and vision. Its drilling activities are distributed across Kuwait onshore basins. In order to monitor, and have the ability to remotely intervene in, drilling operations in any part of the country, KOC commissioned a Real-Time Drilling Decision Center (RTDDC). This state-of-the-art facility provides a platform from which operations may be monitored, interventions made in real-time, and decisions made faster and more accurately, all within a multidisciplinary environment.

For the RTDDC to achieve its intended purpose, it was paramount to complement the deployed cutting-edge real-time data delivery and drilling software technology with a solid operational work plan. This work plan would orchestrate the roles of the different RTDDC stakeholders, define the real-time drilling workflows to be implemented, and set a clear communication plan between the RTDDC team, drilling engineers’ team, and the rig site.

The methodology implemented to develop this work plan:

  • Arranging a KOC/Schlumberger technical workshop to identify different operational requirements for different work groups
  • Identifying key performance indicators directly impacting cost
  • Developing a concise communication protocol that enables proper interventions and escalation practices among involved teams

The work plan main workflows are:

Real-time active monitoring using PERFORMView to observe early signs of potential issues and intervene accordingly.

  • Plan-vs-actual comparisons to detect out-of-trend variations
  • KPI monitoring and reporting
  • Performance measurement and operation efficiency benchmarking using RigHour platform

This work plan has been piloted on four of the deep drilling KOC rigs. Accordingly, the results were utilized to further fine-tune and reach the best working model of how potential direct and indirect cost savings may be achieved. The further plan is to deploy this then-successful work plan and workflow to cover the entire RTDDC rig fleet and expand further to all KOC rigs in order to utilize the RTDDC platform in a way that allows an enhanced decision-making process and evidently an improved overall drilling efficiency.

  • S. Al-Ghunaim (Kuwait Oil Company)
3:00 pm Unconventionals

Fast and Robust Production Data Analytics: Application to re-stimulation candidate selection

  • E. Udegbe (Pennsylvania State University)

Fast and Robust Production Data Analytics: Application to re-stimulation candidate selection

Unconventionals
Thursday, September 14
3:00 pm

With the onset of permanent downhole sensors, such as the Schlumberger FloWatcher system, there is an increased need for better and faster methods to extract useful information from subsurface Big Data. Motivated by techniques in robust real-time face detection, a new data-driven algorithm has been developed to analyze massive volumes of production data from multistage hydraulically fractured shale gas wells, with the objective of predicting their suitability for res-stimulation treatment. Results demonstrate the viability of the proposed framework in identifying favorable candidate wells using only gas rate profiles, with improvements over conventional tools such as type-curve approaches.

By generalizing production data as vectorized 1D images with pixelated values indicating rate amplitudes, a real-time face detection technique is adapted to identify favorable refrac candidates. This is achieved using a cascade of boosted binary classifiers based on a set of simple features, which promotes computational efficiency. The algorithm is trained by identifying patterns in simulated data sets from hydraulically fractured wells. A dual-permeability shale gas reservoir model is used to generate multiple well production profiles by modifying stimulated reservoir volume (SRV) fracture parameters. The trained classifier is then used to discriminate refrac candidates based on field-collected Big Data.

The new approach has been tested using simulated shale gas rate data, which has been designed to present a challenging pattern recognition problem by capturing erratic rate fluctuations and shut-in periods typical of field production records. However, given only two years of rate history, the proposed algorithm has been successful in distinguishing between specified favorable and unfavorable re-stimulation candidates with classification accuracy of over 79%. This has been achieved with near real-time computation speed and symmetric accuracy in detecting both favorable and unfavorable candidates. For the purpose of comparison, the same test data has been analyzed using a popular type-curve method for multistage hydraulically fractured gas wells, and it is infeasible to distinguish between restimulation candidates when their rate responses are plotted on appropriate dimensionless axes.

In the context of reservoir management and decision-making, traditional data analysis methods have become increasingly outpaced by data sophistication. To help bridge this gap, the outcome of this research has the potential to be utilized as an analytic tool in Schlumberger software solutions such as OFM, in order to perform both static and real-time analysis of massive long-duration production data.

  • E. Udegbe (Pennsylvania State University)
3:00 pm Production Operations

Real-time well surveillance and network debottlenecking and optimization to increase production in onshore mature fields

  • N. Boukhallat (Sonatrach)
  • K. Belghomari (Sonatrach)

Real-time well surveillance and network debottlenecking and optimization to increase production in onshore mature fields

Production Operations
Thursday, September 14
3:00 pm

Hassi-Messaoud is one of the biggest mature fields in the world operated by Sonatrach. By having a complex and depleting reservoir, creative solutions are needed to maintain and improve its production. After identifying the main challenges, series of pilots, and a great engagement between Sonatrach and Schlumberger, real-time well surveillance and network debottlenecking and optimization have been identified as the key contributors to increase production:

Real-Time Well Surveillance (RTWS). Identifying the well production decline in gas-lifted wells by only looking at SCADA parameters is not a suitable approach due to the recirculation of gas in case of an obstructed well. RTWS has been developed to help SH-DP identifying an early detection of performance drop in order to take appropriate actions. This solution is using Avocet and OLGA technologies together with real-time data coming through SCADA and identifies the low-preforming wells.

Below, some of RTWS’s key technical values

  • Early detection of performance drop
  • Good rate estimates on individual wells
  • Effective analysis of the well performance
  • Selecting treatments/interventions
  • Evaluating success rate of treatments/interventions
  • Real-time gas-lift optimization.

The implementation of this solution has resulted in an increase in production for the wells under surveillance. There are now 60 wells implemented in RTWS and the plan is to expand this to a full implementation (800 wells) during the coming months.

Network Debottlenecking and Optimization. Sonatrach uses multiphase flow (oil, water, and gas) for their infield transportation of hydrocarbons. This is highly cost effective, centralizing the production processing and thereby minimizing infrastructure at the wellsite. However, multiphase flow introduces a number of challenges that significantly change with time. The increased pressure drop due to liquid accumulation and slugging severely impacts the production and ultimately is time for abandonment.

Transient simulation and analysis was introduced to Sonatrach with the aim of maximizing the production of W2A’ satellite, which was suffering from severe production fluctuations. Despite a relatively stable production at the wellheads, production downstream of the collecting network was highly unstable, varying from an average of 20 sm3/h (night time) to 200 sm3/h (day time). These fluctuations were negatively impacting the production of the subcritical wells. This study was carried out by using PIPESIM and OLGA with the objective of first identifying the cause of these fluctuations and to then find the right mitigation methods. By performing transient analysis, terrain slugging was identified as the main issue that generates the fluctuation at separator. After investigations, two mitigation methods have been proposed and implemented by Sonatrach:

  • Short-term: increasing the total oil production in the pipeline entering the separator
  • Long-term: early separation of the low-performing wells by installing an EPF

These measures helped Sonatrach stabilise the flow and gain in production. This successful approach led to an extension of the same approach to ZCINA network, which is one of the main satellites of the Hassi-Messaoud field.

Real-time well surveillance and network debottlenecking and optimization are now part of the standard workflows and solutions that Sonatrach is implementing in Hassi-Messaoud field. Sonatrach and Schlumberger collaboration in this area is helping Sonatrach to optimise and increase production of this critical field. Rolling out these solutions to the whole field is today in progress.

  • N. Boukhallat (Sonatrach)
  • K. Belghomari (Sonatrach)
3:00 pm Field Development Planning

Field-T (complex turbidites system) simulation experience using INTERSECT and UNO

  • N. Aloysius (PETRONAS)
  • Z. Mokhtar (PETRONAS)

Field-T (complex turbidites system) simulation experience using INTERSECT and UNO

Field Development Planning
Thursday, September 14
3:00 pm

The Field-T is a highly heterogeneous reservoir with a complex turbidites environment. This has been captured in the simulation model and has been a challenge in terms of modeling, that can be directly translated into reasonable simulation time. Due to simulation model, which has an average of 300,000 active cells per sector model (with 3 active sector models to be simulated), more than 70 equilibration and 550 SATNUM regions, and over 40 years of production history, the history match process has become very challenging due the high number of uncertainties in the field, with more than 7 hours of total simulation run time using ECLIPSE.

Introducing INTERSECT, a new technology for high-resolution and complex models, handling multimillion cell models has become an easy task. This model runs now in 0.5 hour (per sector model) with INTERSECT enabling the opportunity to perform an Uncertainty & Optimization task in Field T, reaching a better history matching.

  • N. Aloysius (PETRONAS)
  • Z. Mokhtar (PETRONAS)
3:00 pm Business Transformation

Transforming Your Business from the Ground Up

  • R. L. Rands (Microsoft)

Transforming Your Business from the Ground Up

Business Transformation
Thursday, September 14
3:00 pm

Riding the wave of innovation: what computers playing video games should mean to you. Transforming your business by embracing and safely adopting fail fast mindset and AI.

  • R. L. Rands (Microsoft)
3:00 pm Data and Analytics

Rapid transition to Petrel enables successful preservation of knowledge for ENGIE´s legacy GeoFrame projects in Germany

  • U. Buelow (ENGIE E&P Deutschland GMBH)

Rapid transition to Petrel enables successful preservation of knowledge for ENGIE´s legacy GeoFrame projects in Germany

Data and Analytics
Thursday, September 14
3:00 pm

ENGIE E&P Germany has planned to phase out their Unix/Linux systems wherever possible as maintenance becomes increasingly more versus decreasing efficiency. Reasons for this, amongst others, are the loss of expert know-how and the hosting of old legacy software, rarely used today. Today GeoFrame mainly serves as database for processed seismic data and historical seismic interpretation.

ENGIE E&P Germany completed the transition from GeoFrame to Petrel interpretation platform, with exception of the project migration component. There are some 200 GeoFrame projects online occupying more than 2 TB disk space. When filtering the projects by priority, these numbers are reduced by factor 2. However, initial tests have shown that an average 5 days are required to convert just one GeoFrame project. The outcome of this is, all in all, close to 2 years work time to complete such task. Furthermore, only the main data types are covered and the people knowledge associated with these data is lost.

SIS developed a methodology and internal tools to address these aspects. GeoFrame 2 Studio tool (GF2S) has been developed and improved in the last 2 years, offering the capacity to transfer massive seismic and interpretation data. The Bedrock program has been selected for the well data transfer.

CPS3 mapping data, as well as GeoFrame grids, contours, points, and faults are handled in the conversion. All meta-information accessible in the GeoFrame data managers (creation date, last modified by, creation program…) are captured and written into the Petrel object comments. The format adopted creates tags that are used later in Studio FIND sessions.

A proof of concept was organized with ENGIE E&P Germany with the migration of 2 representative projects. It demonstrates that today the user time needed for the conversion of a GeoFrame project dropped down from 5 to 1 day. The data coverage has been extended and meta-data are preserved in the Petrel platform. In addition, the process is now modular, and the client can exclude some data types, reducing the scope of the migration but also the time required.

Facing these improvements, ENGIE E&P Germany considers that the migration from GeoFrame to Petrel is now feasible and now allocates service days to transform GeoFrame results to Petrel and Studio.

  • U. Buelow (ENGIE E&P Deutschland GMBH)
3:00 pm Subsurface Characterization (Room1)

Integrated formation evaluation using Techlog in complex clastic reservoir, Cheleken block

  • Z. Zhangaziyev (Dragon Oil)

Integrated formation evaluation using Techlog in complex clastic reservoir, Cheleken block

Subsurface Characterization (Room1)
Thursday, September 14
3:00 pm

This study was conducted in an offshore field located 20 km west of the Cheleken Peninsula, Turkmenistan. The studied stratigraphic sequence within the studied field consists of the Early to Middle Pliocene sandstone reservoirs.  

The Reservoir Development department of Dragon Oil planned to acquire a massive formation evaluation suite to better understand the geology and structure of the unexplored part of the Zhdanov field. The LWD BHA included the triple combo log suite, with the Ecoscope tool in the 8.5-in section which provides comprehensive data in real time. The wireline (WL) logging included the quad-combo (PEX-Sonic Scanner platform), nuclear magnetic resonance (NMR), MDT Sampling-Fluid identification, and Sidewall coring. Total of 14 sidewall cores have been acquired. Detailed core analysis will be performed.  

The main objectives of the openhole logging were:  

  • real-time formation evaluation of reservoir with LWD and WL logging tools  
  • Identify fluid type and calculate porosity and permeability by NMR fluid mapping  
  • Wells correlation in reservoir areas, which are highly compartmentalized by faults  
  • Perform image interpretation where applicable  

Density image interpretation was done in the Schlumberger PTS department. The image interpretation supported the seismic fault interpretation, thus confirming the structural interpretation of the field. Reverse fault was confirmed in one of the wells which was supported by open hole logs, image interpretation, and MDT pressures.  

The integrated formation evaluation interpretation of every well was performed in Techlog. It included the petrophysical interpretation, borehole image interpretation, fault analysis integrated with seismic. Two different pressure regimes were identified with the help of sonic/resistivity logs, confirmed by MDT pressure data.

  • Z. Zhangaziyev (Dragon Oil)
3:00 pm Subsurface Characterization (Room 2)

Lowering exploration, appraisal and drilling uncertainties with basin modelling: examples from the Gulf of Mexico

  • R. Tscherny (ConocoPhillips)

Lowering exploration, appraisal and drilling uncertainties with basin modelling: examples from the Gulf of Mexico

Subsurface Characterization (Room 2)
Thursday, September 14
3:00 pm

Basin and petroleum system modeling is an established method and tool to lower exploration risk. It helps to understand and clarify uncertainties of the geological system by a thorough process based numerical modeling. This paper will illustrate how the latest advances of PetroMod enable the industry to bridge the gap from early new ventures exploration to appraisal to development. These new developments take into account implementation of new physical processes, improved numerical methods, and scalability and performance. Especially the recent performance improvements on high performance computing system (HPC) enables to calculate models with more than 100 million cells overnight.

The Gulf of Mexico, with its complex and pervasive salt tectonics, requires a special approach for modeling petroleum systems and geomechanics in exploration and appraisal. We used a high-resolution regional model, spanning 4 protraction areas (~75,000km2) with no less than 600-m cell size to approximate the present-day structures. This model provides the framework and boundary condition for very high-resolution prospect and well scale models. PetroMod’s unique method of embedding those models allows having different scopes and resolutions tailored for each model. It is applied to both petroleum systems and geomechanical modeling.

The petroleum systems models were used to evaluate new prospects in exploration and appraisal to predict pore pressure, temperature, chance for charge occurrence, fluid properties such as gas-oil ratio (GOR), and viscosities. PetroMod’s new fluid method, combining particle tracing with Darcy flow, was used to cope with the large number of finite element cells as traditional methods do not scale properly.

The geomechanical analyses supported COP’s well planning effort based an accurate pore pressure, rock stress, and failure analyses. Once again, the accurate approximation of the salt bodies were key as stress orientation and magnitude changes along the boundary of the salt bodies with the sediment. It is noteworthy, that the basin modeling based geomechanics solution is the only method to capture complex geometries and geo-histories (3D plus time) and their impact on the stress field.

  • R. Tscherny (ConocoPhillips)
3:30 pm

Coffee Break

4:00 pm Well Construction

WITSML, supporting real-time, cross-domain collaboration and now with ETP enabling data assurance and big data drilling analytics

  • R. Philo (Energistics)

WITSML, supporting real-time, cross-domain collaboration and now with ETP enabling data assurance and big data drilling analytics

Well Construction
Thursday, September 14
4:00 pm

Whether from high-volume land operations or high-tier offshore drilling rigs, the availability of real-time data is now regarded as essential for managing well construction. For drillers and subsurface teams, it has become the norm.

The Schlumberger strategy to real-time enable its software has been the adoption and integration of Energistics standards, in particular WITSML. Schlumberger has been a long-term supporter and active contributor to the development of this and the other Energistics standards.

From acquisition system publishing, through data gathering and delivery via Energistics-certified, Cloud or intranet solutions, and onward to real-time–enabled desktop interpretation systems, the entire enterprise uses WITSML to efficiently transfer real-time data. Making the data available in desktop tools, such as Petrel E&P software platform and Techlog wellbore software platform promotes collaboration between the domains and significantly reduces the cycle time required to develop plans and resolve operational issues.

More than 30 Schlumberger applications (internal and commercial) are real-time enabled via a unified WITSML client tool, RT Connect real-time test data transmissions. Acting as a bridge between the consuming application and WITSML servers, RT Connect allows data to be retrieved from, and written back to any compliant WITSML Server, with adapters for all major WITSML vendors.

This functionality supports the Schlumberger global network of operations support centers, where data gathered from real-time operations is used to reduce NPT, identify drilling optimization opportunities or, equally, provide remote geomechanical or pore pressure analysis.

Version 2.0. of WITSML leverages the Energistics Common Technical Architecture (CTA) which provides a foundation for all the current Energistics standards. It has been designed to support data analytics and includes a new data assurance object. The CTA makes it easier to implement the standards and also enables interoperability between them. In addition to the CTA, WITSML 2.0 (along with the other standards) was released with a new transfer protocol, the “Energistics Transfer Protocol” (ETP), which uses web socket technology to allow subscription to the data provider, ensuring real-time updates are sent as soon as they are available. To ensure interoperability, WITSML 2.0 over ETP has a fully documented implementation specification.

ETP allows for transfer of significantly higher volumes of data and has been demonstrated to show a programmatic latency of less than 10 Ms. This helps optimize bandwidth use, supports real-time analytics using high-frequency data, and potentially represents a methodology to replace WITS Level 0.

Coauthors: Nigel Deeks, Sam Marcuccio, Michael Sturm, and Pascal Hochart, Schlumberger

  • R. Philo (Energistics)
4:00 pm Unconventionals

Systemic solution required for model calibration - Kinetix/Visage/INTERSECT/OLGA Model

  • R. McDonald (EP Energy)
  • S. Geetan (EP Energy)

Systemic solution required for model calibration - Kinetix/Visage/INTERSECT/OLGA Model

Unconventionals
Thursday, September 14
4:00 pm

Shale development behaves systemically. Forecasting accuracy attained from a calibrated model requires solving for overall system behavior – the whole is greater than the sum of the parts. Over the years, modeling workflows have grown and expanded to solve more areas of the system. Today we have successfully used a series of numerical engines to translate seismic and wellbore measurements all the way through to surface facility production data.

This study focuses on the use of the numerical engines to assist in solving specific system behavior with the goal of developing better calibration matches, which translates to better forecasting accuracy. In this multi-well, multi-generation (wells of different ages) model, calibration begins in Kinetix using the UFM numerical engine to hydraulically fracture the parent well honoring the lateral trajectory and stimulation recipe. The model is adjusted to match the field measured instantaneous shut in pressure (ISIP). This is our first point of calibration. Next, we perform a production history match. We know that early in the producing life of this well, single phase liquid flow can be assumed, but soon fast drawdown in the fracture field due to limited drainage leads to the wellbore geometry having a significant effect on reservoir inflow. This led us to couple OLGA with INTERSECT to account for fluctuations in the production rates resulting in a more accurate production history match. This was a novel step and we consider it is important in building a good history match in a long lateral well.

Next, the newer well (infill phase) calibration begins. Stress shadows modeled during the UFM injection step affect the shape of the hydraulic fracture network. Depletion shadows caused by production influence the geometry and effectiveness of offset well hydraulic stimulations and the reactivation of the natural fractures. The stress state around the depleted well is recalculated using VISAGE and a new depleted pressure state developed. Kinetix UFM is then used to hydraulically stimulate the wells, and the ISP calibration loop is repeated. The production is then history matched. This gives us a multi-point, multi-well calibrated model, which can then be passed to Kinetix on the Cloud for sensitivity experiments allowing us to digitally evaluate stimulation scenarios. The calibration allows us to use the modeled production numbers directly in our economic models. The preferred treatment could then be selected with more confidence based on cost and oil recovery potential.

Authors - Geetan, Steve Isaac, MacDonald, Richard M; EP Energy Corp; Timothy Pope, JP Dessap Schlumberger

  • R. McDonald (EP Energy)
  • S. Geetan (EP Energy)
4:00 pm Production Operations

CEPSA corporate PDMS: From data capturing to production optimization

  • G. Moreira (CEPSA)

CEPSA corporate PDMS: From data capturing to production optimization

Production Operations
Thursday, September 14
4:00 pm

CEPSA is an integrated oil company, with headquarters in Madrid, Spain. The E&P operated activities are in Colombia, Peru, Algeria, Thailand, and Malaysia. The existing production management and allocation system was implemented in 2004; it was decided that a new and modern system was required. Furthermore new business units had been acquired over the years, which had their own production management and allocation systems. Consequently, a key consideration was to acquire and implement one system across all business units.

With Cepsa E&P´s history and ambitions in mind, the system had to allow easy inclusion of new fields and business units. The CEPSA business units are small and to mobilise the critical mass of the company-wide production technology teams, the system had to enable collaboration between the local assets and the corporate production technology team. On this basis, a vision was created for the foundation of the Digital Oilfield in CEPSA-operated ventures.

The presentation will address how CEPSA deployed the AVOCET for all their assets, a Production Data Management System (PDMS) based solution to meet the imminent need to replace outdated technology and in the same moment provide the starting point for the future vision. The solution covers CEPSA operated and non-operated assets, and is deployed centrally in Madrid, and is accessible from the assets through the CEPSA IT network.

The project delivers a production operations management and decision support system integrating:

  1. Data Management: data capture, QA/QC, data storage centralization and accessibility, and capability to integrate with other disciplines and applications
  2. Visualization: production monitoring, reporting trends, analysis and KPIs, and subsurface and facilities surveillance

  3. Production System Optimization: permanent well performance monitoring using direct-linked models to assess efficiencies for artificial lift systems, facilities capacities, identification of losses, among others.

  4. Reservoir and Assets Optimization: field planning and forecasting.

  • G. Moreira (CEPSA)
4:00 pm Field Development Planning

Well placement optimization workflow using advanced INTERSECT field management features

  • K. Itthisawatpan (PTT Exploration and Production)

Well placement optimization workflow using advanced INTERSECT field management features

Field Development Planning
Thursday, September 14
4:00 pm

Optimizing a greenfield development simulation typically requires unique challenges, depending on the complexity of the field. One of the major difficulties lies in determining the best well location and number of wells to optimize the recovery. Traditionally, well selection relies on a trial-and-error process, which can be subjective and time-consuming. The workflow proposed in this paper aims to resolve such challenges and accelerate the completion of the study, even when new data is continuously supplied through the field development activities.

We developed a workflow to facilitate the greenfield development, with focus on the primary production. The workflow aims to at least match the result from the manual well selection process but with much better efficiency. The development is based on the idea of the simulation opportunity index (SOI). SOI combines hydrocarbon pore volume, well productivity, reservoir pressure, and fluid saturation into a single parameter and then manually selects development wells centered on it. This work introduces automatic features to the process and also allows the index to be calculated in real time from the dynamic reservoir responses.

The study shows that a simple two-step workflow can satisfy our objectives:

  • Iteratively select a set of drainage points based on hydrocarbon distribution in the reservoir (e.g., hydrocarbon pore volume and moveable oil maps). These points become the potential locations for the development wells.
  • Open the wells sequentially based on rig availability and the combination of local pressure, potential production rates, saturation, and the distance to the existing wells at each time step. The dynamic well ranking was implemented with INTERSECT Field Management. We introduced the Alpha Factor to represent the relative weight between pressure and potential production rate. Effects of the Alpha Factor are investigated and discussed further in this paper.

The workflow shows several advantages and is applicable for various development scenarios, including vertical wells, horizontal wells, and mixed well types. An optimal field development scenario can be selected by constructing a well creaming curve. Furthermore, because of its consistency, the new workflow can also help identify the effects if new information is incorporated into the model.

The workflow proposed by this work represents a successful extension of the generally accepted idea of SOI. By introducing automatic features, greenfield development optimization can be performed with a more consistent and expeditious process.

  • K. Itthisawatpan (PTT Exploration and Production)
4:00 pm Business Transformation

Practical workflows for reservoir management and production enhancement in mature fields under waterflooding, North Kuwait

  • H. Al-Zaabi (Kuwait Oil Company)

Practical workflows for reservoir management and production enhancement in mature fields under waterflooding, North Kuwait

Business Transformation
Thursday, September 14
4:00 pm

Reservoir management is a dynamic process due to the uncertainties in reservoir performance resulting from the inability to fully characterize reservoirs and flow processes.  Integrated solutions are especially important to formulate plans for today’s mature reservoirs under waterflooding.  The reservoir operation and field management need to be handled as a system, and therefore need a multidisciplinary approach. Since 2012, the Schlumberger team working together with KOC have adapted, created, and utilized several workflows to help KOC to produce and recover more hydrocarbons in Sabriyah field. The developed workflows cover a wide range of areas and applications—reservoir management (Petrel, OFM), production optimization (Petrel, OFM, PIPESIM), and reservoir simulation (Petrel)—and require the participation of G&G, reservoir, and production engineering specialists. 

This article will demonstrate how the following easy-to-use integrated workflows are put together to help maximize the economic recovery of asset reservoirs: 

PVT Properties Tool©: This workflow is designed to calculate the oil properties in any place of the reservoir taking into consideration areal and vertical variations based on trends. 

Opportunity Maps©: This is a combination of updated reservoir pressure and fluids’ properties to provide a fast way to identify areas of opportunity to increase/decrease injection or production based on the development strategy. 

Waterflooding Patterns/Segments Review Workflow© and Allowable Tool©: This integrated analytical workflow includes several tools like analysis of production and injection trends, diagnostic plots mostly in OFM to assess good vs. bad water, Hall plots, reservoir pressure data, tracer data, salinity changes, and PIP trends. Geological analysis (cross-section, well correlation, sand thickness map) for each layer is integrated in each pattern/segment review to support connectivity (or lack of).  Instantaneous and cumulative VRR are calculated and compared with overall exploitation strategy. 

Structured Integrated Proactive Production Optimization Workflow©: Production optimization is a continuous iterative process (cycles) to improve production, especially in mature fields. This workflow facilitates the identification of opportunities for production optimization with a proactive approach focusing on flowing wells and rigless interventions to tackle production challenges and achieve production targets. The OFM heterogeneity index (HI) process is utilized to rapidly demonstrate production gain opportunities.  This provides family-type problems that are then represented by type-wells for detailed diagnostics. 

Conclusions: Continuous application and embedding of such structured integrated workflows as standard best practices in a consistent and systematic approach improves overall asset management in terms of maximizing production and recovery.

  • H. Al-Zaabi (Kuwait Oil Company)
4:00 pm Data and Analytics

Studio as a global and corporate database for Petrel data?

  • T. Mueller-Wrana (Deutsche Erdoel AG)

Studio as a global and corporate database for Petrel data?

Data and Analytics
Thursday, September 14
4:00 pm

Besides oil and gas, geophysical data have a high value for an E&P company. Hence, it is crucial to know that to find and to share these data an excellent inventory of quality-checked data is required.

At DEA, we use several other sources (for well and seismic data) and Petrel reference projects to provide users with their data they need— ensuring accessibility and required confidentiality. Thus, DEA has set many authorizations on assets in about 40 countries in more than 160 Petrel reference projects. The long-term goal to handle the geophysical data at DEA is to map this complex environment into Studio to have one corporate database for our Petrel users. On top the data needs to be easily accessible and searchable.

Kick-off was in 2014 and with Studio 2013. In Studio 2013, DEA encountered mainly two issues: (1) no AD -group support within Studio and (2) internal 2D seismic present in Petrel reference projects.

While looking for solutions in cooperation with Schlumberger, DEA used the Studio indexing functionality to provide Petrel users with information about available data in the Petrel reference projects. Studio indexing runs every night. The resulting index files are currently shared with the local Petrel installations of the users.

To achieve the project’s objectives, the first big challenge was to externalize the 2D seismic previously stored internally in Petrel reference projects. The project’s main requirement was an external realization of the 2D seismic keeping their GUID. Keeping the GUID ensures the bidirectional connection of interpretations between the 2D seismic of a survey in the reference and the user’s projects. A simple reconnect workflow is ready to link missing 2D seismic in the user’s projects with minimal effort for the users.

This challenge was bundled into a joint project with Schlumberger in 2016. SIS created a Petrel workflow using a combination of Petrel out-of-the-box functionality, custom-developed technology and internal SIS technology to keep the GUID of the 2D seismic.

On the SIS Global Forum I would like to present the results of this project.

  • T. Mueller-Wrana (Deutsche Erdoel AG)
4:00 pm Subsurface Characterization (Room 1)

Wellbore anisotropy analysis for geophysical and geomechanical applications

  • F. Karpfinger (Schlumberger)
4:00 pm Subsurface Characterization (Room 2)

Deep water oil and gas discovery of Pearl River Mouth Basin guided by geological and geophysical integrated techniques

  • W. Zhang (CNOOC)

Deep water oil and gas discovery of Pearl River Mouth Basin guided by geological and geophysical integrated techniques

Subsurface Characterization (Room 2)
Thursday, September 14
4:00 pm

Baiyun Depression is a third-grade tectonic unit of the Pearl River Mouth basin and the largest Cenozoic sag of the continental margin of the northern South China Sea. The Baiyun deepwater area is one of the most important deepwater oil and gas exploration areas of offshore China. Under the guidance of a reservoir forming pattern, named "near-source accumulation and dominant pathways of oil and gas migration" within the northeast Baiyun Depression accumulation system, firstly, the regional structures, fault systems, dominant oil-gas migration and accumulation units are defined by 3D seismic interpretation, with the understanding of differential hydrocarbon accumulation in Baiyun Depression: oil in the inner fairway, gas in the outer fairway. Secondly, combining coherent attributes and detailing the combination of minor faults and complex faults, the possible risks of lost circulation during the drilling process are avoided and the well design process is optimized. Meanwhile, based on multi-attribute extraction and cluster analysis, the sedimentary facies and distribution of the limestone and sandstone reservoirs are confirmed in the research area through well-tie seismic cross-section techniques. Finally, reservoir inversion and hydrocarbon detection technique predict the distribution of high quality reservoir and fluid properties in the area. Based on these new understandings and techniques, the medium size oil and gas fields of LH27-1, LH29-4, LH20-2, and LH21-2, with the features of high yield and light crude were discovered. These discoveries further promote the simultaneous exploration of both oil and gas in the Baiyun Depression deepwater area.

  • W. Zhang (CNOOC)
4:30 pm Well Construction

Planning a horizontal well in Middle Montney, KAKWA project with precommercial DrillPlan

  • E. Abou-Khalil (Seven Generations Energy)
4:30 pm Unconventionals

Effective hydraulic fracture design using an integrated 3D modeling approach: A case study of a tight reservoir in India

  • V. Pandey (ONGC Ltd.)

Effective hydraulic fracture design using an integrated 3D modeling approach: A case study of a tight reservoir in India

Unconventionals
Thursday, September 14
4:30 pm

Field A is a prominent field in the western onshore asset of Oil and Natural Gas Corporation (ONGC). It is a multi-layered, heterogeneous reservoir on depletion drive with very low permeability. Facies are generally silty with thin intercalation of sand. Conventionally the wells have been producing on an average of 3-4 m3/d and the recent horizontal wells were not deemed successful.

This paper presents a study which better models the impact of past hydraulic fracture operations in key wells and uses this understanding to optimize the stimulation strategy for future wells. Economic exploitation of such a field should be supported by detailed petrophysical and production data analysis, integrated 3D mechanical earth modeling, production stimulation engineering of fracture jobs and 3D hydraulic fracture modeling, and production forecast sensitivity analysis.

Based on the current study, a phased approach to field development planning is recommended with a balanced focus on data acquisition, increasing reservoir understanding and building up production potential. This paper elucidates techniques to maximize reservoir understanding and allow optimization of hydraulic fracture design and operations in terms of casing diameter, job size, and design. The prognosis for multi-stage hydraulically fractured horizontal wells deployment is one of caution. Hydraulic fracture modeling indicates the likelihood of fracture height growth into an unwanted zone. The study also showcases a seamless integration of technologies from log interpretation to hydrofracturing design and production forecast with Petrel and INTERSECT dynamic simulation as the main platform. Overall, the case study showcases different factors that govern the development of a tight oil reservoir and the ways to characterize and quantify these uncertainties.

Note. Authors: Vivek Pandey, Raman Kumar Singh and Harish Meena ONGC; Sanjoy Kumar Khataniar, Adrian Rodriguez Herrera, Christophe Darous, Vinil Kumar Reddy Mukku, Ankit Agarwal and Ankit Dutt, Schlumberger

  • V. Pandey (ONGC Ltd.)
4:30 pm Production Operations

Flow assurance dynamic simulation models: Continuity between design and operations

  • A. Di Lullo (Eni)

Flow assurance dynamic simulation models: Continuity between design and operations

Production Operations
Thursday, September 14
4:30 pm

Dynamic simulators, and in particular OLGA, are widely used during the design phase to identify the best field architecture and to demonstrate the feasibility of the main field operations, thus strongly contributing to the definition of the operating philosophies and procedures.

During the production phase, instead, the practical use of such simulators is somewhat more limited due to a number of reasons, including: (1) the highly specialized nature of such dynamic simulators (perceived or real); (2) partial model handover from design to operations; (3) the complications related to the setup of a seamless transfer of production data to the simulations; (4) the difficulty to tune dynamic (mechanistic) models to observed behaviors; (5) longer simulation times compared to point-models and correlations; and (6) the limited number of licenses and their high cost, which makes the resources devoted to operational follow-up compete with those devoted to design.

The commercial systems developed ad hoc for operators (i.e., the so-called "online" tools) only partially solve the above limitations because several types of useful analyses (diagnostic studies, design of special field activities, new tie-ins, sensor recalibration, etc.) are not easily dealt with inside of the scope of the online tools and require significant offline activities.

In order to solve all the above issues, we started adopting a different point of view in between offline and online simulations, which might be described as "near online": within the context of our design tools, dynamic models are easily fed with and constantly process production data in an uninterrupted stream of discrete simulations, providing information potentially useful for simulator quality check, problem diagnosis/troubleshooting, operational optimizations, etc. Moreover, at any time, such models can be exported, modified, adapted to design studies, and subject to complex tunings for any purpose, thus facilitating a rich interplay between designers and operators.

All of this has to be performed with very limited or no human intervention and has been implemented within the Eni proprietary e-fast™ system, which is the web-based set of tools used to automate and speed up the design activities in Eni.

In the presentation, the status of our attempts will be presented together with a preliminary judgment of their effectiveness.

Co-Authors (all Eni): Bianco Amalia, Mezzapesa Domenico, Bottani Cristina, Aliverti Eleonora

  • A. Di Lullo (Eni)
4:30 pm Field Development Planning

A successful application of combined reservoir coupling and network modelling in INTERSECT

  • R. Sabatino (Eni)
  • R. Rodriguez (Eni)

A successful application of combined reservoir coupling and network modelling in INTERSECT

Field Development Planning
Thursday, September 14
4:30 pm

The studied reservoir is an offshore ultradeepwater gas field complex containing four gas accumulations of different geological age. Each of the reservoirs has been characterized and modelled separately due to the areal extension and to the overall thickness of the vertical sequence.

The development scenario foresees the monetization of the gas resources through onshore LNG trains; the upstream development envisages a long tieback from the wells to the onshore inlet facilities and the LNG plant. The production from the wells is gathered in the offshore manifolds and transported onshore in multiphase flow through the export pipeline.

Within this framework, many challenges arise in terms of reservoir simulation: (1) the dimension of the 3D simulation models: 1 to 2 million of active cells per reservoir, which eventually affects the simulation runtime; (2) the need of coupling the independent models in order to simulate them together with the same production constraints and a common subsea gathering and export system; and (3) the opportunity to incorporate a "network model" in the reservoir simulations, allowing to take into account the pressure drops across pipelines and between wells, manifold, and final onshore host.

The reservoir dynamic simulations are currently run using both ECLIPSE100 (ECLIPSE), the standard black oil reservoir simulator, and INTERSECT, the next generation high-resolution reservoir simulator.

The coupling functionality within INTERSECT currently requires some extra effort to configure, which we have encapsulated in a bespoke in-house script. The network modeling also poses some additional challenges, as it requires a separate data set and extra plugin for field management - ECLIPSE Network Simulator (ENS) - and uses a different approach from the standard ECLIPSE network option.

This integrated reservoir study is one of the first successful Eni case studies of combined implementation of the "reservoir coupling" and "network modeling" functionalities using INTERSECT. The recent work performed in collaboration with Schlumberger offers the advantage of reducing run times considerably, without jeopardizing the accuracy of the gas and water production profiles.

Note. Authors: C. Benvenuti, R. Rodriguez Lopez, R. Sabatino, A. Thompson

  • R. Sabatino (Eni)
  • R. Rodriguez (Eni)
4:30 pm Business Transformation

Safely transitioning from ECLIPSE to INTERSECT: Inject QC & optimize expertise with Petrel Guru

  • N. Eberle (Total)

Safely transitioning from ECLIPSE to INTERSECT: Inject QC & optimize expertise with Petrel Guru

Business Transformation
Thursday, September 14
4:30 pm

Total joined Chevron and Schlumberger to become full partners in the INTERSECT consortium in May 2012. Two years later, after confirming the benefit of INTERSECT on operational studies, Total management challenged the reservoir engineers to transition 80% of the HQ simulation models from ECLIPSE to INTERSECT by 2017 and reach 50% of usage for operated assets in the affiliates. To achieve this target, the deployment plan involves many actions, among which is a phased migration campaign along with a systematic QC.

The INTERSECT deployment team has the objective to support users for this transition, but how to optimize the expertise in a massive transition under time and manpower constraints? How to systematically identify, quantify, and diagnose discrepancies in results between the simulators? How to guide the users through the different types of simulation results/reports, help them focus on the relevant information, and propose them some adequate remedial actions? How to propagate good practices without drowning the users with tons of technical notes and software manipulations?

Petrel Guru offers a framework for knowledge management and, more importantly for our purpose, some reporting tools based on the native in-built scripts called “workflows”. Such workflows can relatively easily be designed by advanced Petrel users with notions of programming through a simplified coding interface. They give the ability to interactively query some input from the users, then automatically design different views/plots (3D, maps, line plots, etc.), create new QC results/properties, extract statistics, parse text files, etc. We combined those facilities with Guru quality reporting tools to design an automated “ECLIPSE to INTERSECT migration QC workflow”. From a very limited user input (ECLIPSE and/or INTERSECT cases), the workflow is able to compare and/or analyze the different simulation output as the expert would do, raise some concerns and recommendations, and then generate an advanced migration report. As a bonus, all views are now ready for further investigation/customization if necessary.

Such workflows provide a standardized migration report and can be deployed to non-advanced Petrel users since very little manipulation is required: reservoir engineers can focus on analyzing results and perform the suggested remedial actions with limited/no support. Simulation experts can concentrate on more-complex cases and eventually inject more expertise into the Guru workflow. We foresee other possible applications of Guru to help our INTERSECT deployment like beta testing, benchmarking, or training.

  • N. Eberle (Total)
4:30 pm Data and Analytics

Petrel Studio for reservoir data management: Implementation to Eni Mozambique assets

  • M. Dossola (Eni)
  • A. Luciani (Eni)

Petrel Studio for reservoir data management: Implementation to Eni Mozambique assets

Data and Analytics
Thursday, September 14
4:30 pm

The scope of this presentation is to outline the implementation of Petrel-Studio to support the Eni Mozambique asset team with managing well, seismic, and modelling data and related interpretations. The motivation for testing and adopting Petrel-Studio was fueled by the serious necessity of providing the asset team with a predefined but flexible and customizable tool for data classification, sharing, consolidation, ease of access, and user collaboration.

The presentation will show the main features of the customized Studio implementation to the Mozambique case, highlighting the key advantages with using this tool as well as the potential improvements.

Note. Authors: Authors: Massimo Dossola, Andrea Luciani, Kufre Edehe

  • M. Dossola (Eni)
  • A. Luciani (Eni)
4:30 pm Subsurface Characterization (Room1)

Deploying geomechanics across the asset: Examples of solutions for completion and production integrity and optimization

  • V. De Gennaro (Repsol)

Deploying geomechanics across the asset: Examples of solutions for completion and production integrity and optimization

Subsurface Characterization (Room1)
Thursday, September 14
4:30 pm

During reservoir life, pressure changes due to injection/production can induce major changes of the state of stress within the reservoir and its surroundings. These changes may have multiple effects over time resulting sometimes in a global picture of the reservoir in terms of mechanical and hydraulic properties that may differ passing from early development to sustained production. Changes induced by injection/production and reservoir depletion and or repressurization can result in (but not be limited to) non-uniform deformation (e.g., swelling, compaction), local instabilities (e.g., fracturing), reactivation of existing discontinuities (e.g., faults, natural fractures), re-orientation of principal stresses, and stress magnitudes alterations. The occurrence of these phenomena can induce modifications of reservoir transport properties by means of changes in reservoir permeability (as a consequence of compaction and/or swelling) and conductivity of discontinuities (as a consequence of fracturing and/or re-activation). In weak formations, relative changes in reservoir pressures and wellbore pressure (drawdown pressure) can lead to formation failure and solids production, putting surface facilities at risk.

This work presents examples of deployed solutions to assess the long-term impact of injection and production on reservoir performances and to identify conditions leading to solids production during sustained drawdown. Results of this study have been evaluated with regard to productivity of existing wells as well as drilling integrity and well placement of future wells. The approach has been developed by means of coupled geomechanics modelling using Petrel Geomechanics software and the ECLIPSE dynamic reservoir simulator. Ad-hoc solutions at the well scale developed on purpose using Ocean functionalities in Petrel have also been developed. The entire process starting from the single well geomechanics analysis, passing through the 3D structural characterization and properties modelling, in-situ pre-production stress modelling, and. Finally, production modelling is described.

  • V. De Gennaro (Repsol)
4:30 pm Subsurface Characterization (Room 2)

WebGS: Collaborative web-based platform for GeoSphere 3D reservoir characterization on the cloud

  • F. Antonsen (Statoil)

WebGS: Collaborative web-based platform for GeoSphere 3D reservoir characterization on the cloud

Subsurface Characterization (Room 2)
Thursday, September 14
4:30 pm

Following the successful application of GeoSphere for geosteering in the North Sea fields, Statoil and Schlumberger started collaboration to develop workflows to exploit the full potential of GeoSphere data and apply the technology in challenging environments. GeoSphere reservoir images bridge the gap between wellbore, geologic scale features, and seismic, and can be used to optimally place the wells in complex targets and for 3D reservoir characterization in a volume around the borehole.

Access to accurate and reliable forward modeling and inversion on realistic geomodels is a critical requirement for understanding and validation of GeoSphere interpretation. Modeling and inversion is used to assess how structural complexities, lithological changes, oil-water contacts and saturation affect inversion results. It is a key for quantitative robust interpretation and geomodel update.

The WebGS platform, developed as part of the collaboration, integrates Statoil Compound Earth Simulator (CES) used to produce realistic geological models and Schlumberger advanced 2.5D and 3D modeling and inversion of GeoSphere responses. The system is now routinely used in case studies, allowing the users to perform pre-job well placement feasibility analysis and post-job model refinement.

The technology behind WebGS is a modular Web platform that hides all of the complexity of the modeling and inversions algorithms. Users can upload their data to the application’s virtual file system, visualize reservoir resistivity models and GeoSphere and resistivity logs, launch modeling jobs, and watch the inverted images unfold as the job progresses, all in the web browser. The system enables multiple users to view and edit the same model and observe and control the same job in a collaborative way. The simulation codes are run on the remote clusters or on the cloud.

We will present the application of WebGS and CES models for 3D characterization in Norwegian continental shelf wells. The examples illustrate mapping of 2D structural complexity, including a complex saturation J-function, and using the system to update the geomodel. WebGS Is also used to understand the potential benefits of GeoSphere reservoir mapping in the pre-job planning phase, as well as to evaluate sensitivities, depth of investigation in specific scenarios and to analyze how the structural model uncertainties may be affecting the interpretation.

We will also present the results of the first deep 2D azimuthal imaging application to GeoSphere data. By imaging heterogeneities on a side, the new inversion enables 3D reservoir mapping, improving understanding of 3D reservoir structure and fluid distribution around the wellbore.

  • F. Antonsen (Statoil)
5:00 pm Well Construction

Lukoil improves drilling performance in Black Sea with integrated real-time technology and virtual teams

  • T. Kasumov (Lukoil)

Lukoil improves drilling performance in Black Sea with integrated real-time technology and virtual teams

Well Construction
Thursday, September 14
5:00 pm

Black Sea deepwater offshore Romania, with complicated geology and unexpected formation pressure changes, presents many challenges to drilling operations. In 2015, Lukoil drilled three exploration wells in the area. Two of these wells employed the Seismic Guided Drilling (SGD ) technology based on Omega/Petrel platform, with multidisciplinary virtual teams spread over three continents. An SPA was colocated within the Drilling Team in Romania. These wells were completed ahead of AFE and schedule, significantly improving the prior well’s drilling experience.

Conventionally, an earth model is built prior to drilling and used for planning the well. This model typically comes from a regional data processing for exploration and does not have the resolution and accuracy required for drilling a specific location. Furthermore, once the drilling starts, this model remains mostly unchanged, even though drilling information indicates that the model is wrong.

The Lukoil drilling team used SGD technology to overcome these limitations. After the first well was drilled, the well logs were used to build a new predrill model for the second well at about 10 km distance. The model included high-resolution velocities used for accurate depth imaging, pore pressure prediction, and fracture gradient prediction. A rock-physics model was built based on the well logs and pore pressure measurements from the first well, and applied to the second well velocities for predrill prognosis. Together with the fracture gradient, this provided a safe mud weight window prediction.

After the well was drilled half way down, the model was rebuilt using new well logs and pressure data. SGD1 accurately predicted the location and magnitude of a pore-pressure ramp and the subsequent benign pressures, while also correcting the reservoir target depth by more than 40 m, helping Lukoil to drill on time to TD without major issues.

In the third well, at about 20 km distance, both first and second well information were used to build a new drilling earth model with the new technique and further calibrated with the while-drilling data. Target depths were improved by about 30 m. Based on new velocities; the best mud weight windows for the critical sections were calculated. Lukoil drilled ahead with greater confidence and reached TD in the reservoir considerably ahead of AFE and schedule.

  • T. Kasumov (Lukoil)
5:00 pm Unconventionals

Zhaotong national shale gas pilot block case study: Intergrated geological modeling and its application for sweet spot prediction in shale gas reservoir

  • G. Wang (Petrochina Zhejiang Oilfield Company)

Zhaotong national shale gas pilot block case study: Intergrated geological modeling and its application for sweet spot prediction in shale gas reservoir

Unconventionals
Thursday, September 14
5:00 pm

Unlike the successful development of shale gas basins in North America and other nearby domestic shale gas development zones, Huangjinba block has shown mountainous shale gas features of “strong transformation and over mature”, so the integrated geological and engineering study of reservoir quality, drilling quality, and completion quality is quite necessary. To achieve this integrated evaluation of shale gas, geophysical methods are the core technology followed by 3D geological modeling technology to perform on-site real-time feedback and iterative model updates in order to guide the geosteering to ensure the drilling ratio of high quality shale zone protects the integrity of wellbores and real-time monitor and adjust the parameters of the stimulation. By sweet spot identification technology with 3D seismic AVO inversion and ant-tracking, we could get shale gas reservoir properties including TOC, gas content, and porosity at all, predict the multiscale natural fractures, and geomechanics elastic parameters. By 3D geological modeling technology, shale gas reservoir property models, a multiscale fracture system model, and a geomechanics model were built and iteratively updated with real-time new data from drilling, completion and logging.  By continuing to deepen the understanding of this shale gas block in both geology and engineering, we provided real-time support to well placement, drilling, and hydraulic fracturing, minimized the drilling risk, increased the drilling ratio of high quality gas shale zone, and increased the well performance. This is very valuable experience and a reference example for shale gas exploration in the future.

  • G. Wang (Petrochina Zhejiang Oilfield Company)
5:00 pm Production Operations

Portfolio optimization and restructuring strategies for NOC under the declining oil price environment

  • Z. Wang (RIPED, PetroChina)

Portfolio optimization and restructuring strategies for NOC under the declining oil price environment

Production Operations
Thursday, September 14
5:00 pm

Since June 2014, the International oil price has been declining and fell below 50 USD per barrel by the end of 2014. Although the price has partially recovered in the first half of this year, it hasn’t shown signs of further recovery. The high uncertainty of the oil price coupled with the bearish forecast on the capital market exerts a significant impact on oil company operations, and the entire oil industry is facing the risk of reshuffling. 

At the China National Petroleum Corporation (CNPC), an exercise of portfolio optimization and restructuring has been carried out to optimize its overseas assets. First, a sensitivity analysis was carried out to measure the economic impact of price fluctuation, workload, and investment-level changes on projects under different fiscal terms, such as concessionary, production sharing contract (PSC), and technical service contract (TSC).  

Next, based on the economic evaluation results and initial development plan for the projects, portfolio optimization and restructuring were carried out in two steps as follows:

Step 1: Optimize the existing projects to meet company strategic goals by controlling the investment ceiling and delaying the on-stream time of large-scale projects without considering assets divestiture and acquisition. Furthermore, more emphasis was put on the projects with higher liquid production ratio to take advantage of the higher economic return of liquids compared to gas to improve the overall portfolio economic results. 

Step 2: Include divestment and acquisition options based on the results from the

Next, based on the economic evaluation results and initial development plan for the projects, portfolio optimization and restructuring were carried out in two steps as follows: 

  • Step 1: Optimize the existing projects to meet company strategic goals by controlling the investment ceiling and delaying the on-stream time of large-scale projects without considering assets divestiture and acquisition. Furthermore, more emphasis was put on the projects with higher liquid production ratio to take advantage of the higher economic return of liquids compared to gas to improve the overall portfolio economic results.
  • Step 2: Include divestment and acquisition options based on the results from the Step 1 optimization. Divestment of high risk, low return assets, such as unconventional oil and gas, oil sands, and deepwater projects were included as whole project sales or equity dilution. Conventional onshore projects or potential EOR projects were set as acquisition targets to meet the national energy security requirements and to ensure the sustainable development of the company.

The conclusions of the paper are the following:

  1. For CNPC’s overseas oil and gas assets, under the current conditions of declining oil price and controlled investment in the five-year plan, large-scale projects under TSCs and projects with strong profitability will take priority for investment. This is to secure the contribution of these projects to the overall company cash flow. For PSC projects, investment needs to be controlled and the return on investment needs to be stabilized. For concessionary projects, which are most impacted by oil price, investment will be reduced and capital outlay will be delayed.
  2. The investment sequence for proposed production projects needs to be controlled according to the optimization results.
  3. The divestment candidates need to be confirmed, and the divestment strategy will be quantified.
  4. The scale and degree of acquisition and participation of new projects will be estimated.
  5. Finally, desired optimal investment portfolios and business strategies will be selected in order to provide a solid base for management decision-making under the low oil price environment.

  • Z. Wang (RIPED, PetroChina)
5:00 pm Field Development Planning

Dynamic Simulation of Economic Simulation in Jambaran Tiung Biru Gas Development Project

  • E. A. Kusuma (PT Pertamina EP Cepu)

Dynamic Simulation of Economic Simulation in Jambaran Tiung Biru Gas Development Project

Field Development Planning
Thursday, September 14
5:00 pm

The Cepu Production Sharing Contract (PSC) was signed in 2005 and includes participating interests by the following contractors: 1) PT Pertamina EP Cepu (PEPC), holding 45%; 2) ExxonMobil, comprised of ExxonMobil Cepu Ltd. (EMCL), as the operator holding 20.5% percent and Ampolex (Cepu) Pte. Ltd, holding 24.5% percent; 3) Four local government-owned companies represented by BKS PI Blok Cepu(BKS) holding 10%.

The contractor under Cepu PSC has a hydrocarbon discovery within its contract area, known as the Jambaran field. PT Pertamina EP (PEP) is the contractor of the working area covered by the Kontrak Minyak Dan Gas Bumi Pertamina with BPMIGAS dated 17 September 2005.

PEP has a hydrocarbon discovery within its contract area, known as the Tiung Biru field.

In early 2010, PEP drilled the Tiung Biru 1 discovery well in the adjacent Jawa Bagian Timur Area III (“PEP” Block), directly west of the Cepu Block. A data trade between Jambaran and Tiung Biru fields, along with subsequent subsurface assessments, confirmed that the resources are part of the same carbonate build-up structure, are within a continuous reservoir, and have the same fluid contacts. The Tiung Biru discovery is therefore an extension of the Jambaran field onto Pertamina EP’s block.

Pursuant to the law of Indonesia, contractors are required to unitize fields with overlapping reservoir. PT Pertamina EP Cepu has been appointed as an operator in unitized fields between Jambaran (Blok Cepu) and Tiung Biru (Blok PEP) to develop a gas project (one of the biggest gas projects in Indonesia). In developing those unitized fields, management always asked to run various simulations of economic calculations based on various input assumptions such as CAPEX, OPEX, gas and condensate price, production profile, etc. to reach the optimum economic indicator (IRR and NPV), and sometimes management needs changes in rush and urgent jobs for the decision-making process.

All economics have been calculated based on the PSC terms (economics have been divided between the Cepu and PEP PSCs). The fiscal terms for the Cepu PSC are per Cepu PSC. The Jambaran Tiung Biru (JTB) Gas Project (POD II) economics will be represented on an incremental basis to the Banyu Urip Project (POD I), which cover crossflow cost recovery. Economics will also be represented on a “total Cepu Block” (POD I + POD II) and standalone (POD I only) basis for illustration purposes only.

To run economics on an incremental basis, was complicated and took a long time for run iterations in an Excel spreadsheet because we created a data table for full field sensitivities for management. Furthermore, management wants to acquire the participating interest of Exxon as permanent sole risk operation for gas development with certain compensation in advance for Exxon and, once again, we need to calculate certain economic calculations to compute whether such transaction is feasible for PEPC or not in Excel. It is a time consuming and error-prone calculation and poses danger for decision making.

The implementation PEEP software helped to run the economics so quickly and so easily in contrast to using the Excel spreadsheet, which required time to process simulation / sensitivity or, moreover, to conduct Monte Carlo simulation. Results of using PEEP are more reliable and accurate and offer efficiency, helping a lot for better decision making. In addition, the method is not time consuming.

  • E. A. Kusuma (PT Pertamina EP Cepu)
5:00 pm Business Transformation

An integrated technology platform to standardize and facilitate the FEL process definition, execution and validation, Phase1

  • E. J. Villalobos (PEMEX)

An integrated technology platform to standardize and facilitate the FEL process definition, execution and validation, Phase1

Business Transformation
Thursday, September 14
5:00 pm

The principal objective of building this technology platform is to create a system for revision of information, quality control of engineering studies, and documentation of the results of projects in an efficient, standard, and direct manner. In developing this technology platform, several software components have been utilized and developed as below: Petrel platform, Guru, Studio, Petrel plug-in, webpage, and Database.

One of the main objectives of the project was proposing a standard method to construct and document the subsurface models. For this purpose, two different documents were generated through the Guru platform. The first one was to guide the user about the industry standards to build reliable static and dynamic models. The second one instructed how to prepare the Petrel project to facilitate evaluation. The Petrel plug-in assists with the reporting part of the studies, to follow certain templates and standards, also the reports will be saved in a database that is connected directly to the plug-in system and is accessible from the Petrel environment as well as standalone. Petrel Studio creates a collaborative environment for communication between different parties involved in the FEL project. The notification functionality between the engineers in the asset and peers is done by this component. The webpage is available for visualization purposes and mostly used for management. All the deliverables, reports, and projects are visible from the webpage that has been developed. Finally, the database serves as a place to save all the deliverables of the project and to protect and secure the information.

There have been several benefits and motivations for implementing this system in PEMEX Corporation. For the engineers at the asset, the exchange of experience with the network of experts in PEMEX will enhance their technical understanding. The proposed standards and workflows to build the subsurface model facilitate the reporting process. In the levels of the organization, proper budget distribution between the assets, based on reliable production potential is one of the main achievements. Reducing time and cost of project technical evaluation compared to the traditional onsite evaluation process, through omitting the risk of traveling back and forth is another main benefit of the project. Being able to visualize and track the results of the studies at different assets through developed web-page and assuring that the results of the studies are being saved, protected and accessible at any time in a central database is another advantage of the project.

  • E. J. Villalobos (PEMEX)
5:00 pm Data and Analytics

Automated machine learning workflows for well log outlier detection and reconstruction

  • T. Conroy (Woodside)
5:00 pm Subsurface Characterization (Room1)

Advanced geomechanics solutions to support drilling and reservoir management

  • A. Onaisi (Total)

Advanced geomechanics solutions to support drilling and reservoir management

Subsurface Characterization (Room1)
Thursday, September 14
5:00 pm

It has long been recognized that production-induced stress changes during the life of a reservoir can cause challenges for field development and production. Reservoir compaction, surface or seafloor subsidence, fault reactivation, caprock failure, and completion failures (casing and cement) are typical examples of such problems.

In Total, geomechanics is widely applied in the domains of drilling and reservoir management. More recently, geomechanics has been identified as a key component for the evaluation and development of unconventional plays.

In this presentation, an example of a 3D geomechanical analysis carried out to estimate reservoir compaction, induced seabed subsidence, and fault reactivation due to depletion occurring during production is proposed. Consequences on casing-cement integrity of producing wells have also been investigated. Several wells were used for preliminary 1D geomechanical modeling. Mechanical properties were calibrated against numerous laboratory test results and then up-scaled and populated in Petrel through a 3D grid built from interpreted horizons. Reservoir geomechanics modelling with the Visage geomechanical simulator coupled to production modeling performed with Eclipse was used in Petrel Geomechanics to compute preproduction stresses and estimate stress changes and induced deformations during 16 years of production.

Results of the analysis showed the impact of production on stress changes and on reactivation of some faults. In particular, it appeared that the arching effect induced by fault reactivation brought to different behavior for reservoir compartments, with alternative compaction and extension effects in zones surrounding the critically stressed fault. High-resolution near wellbore modelling using the Ocean plug-in was used to analyze casing integrity of a production well using the 3D geomechanics modelling described above. Deformation of the casing was quantified over the entire production period.

  • A. Onaisi (Total)
5:00 pm Subsurface Characterization (Room 2)

The role of mobile shale in forming fold belt anticlines and hydrocarbon accumulations in Sabah Basin, Malaysia

  • B. Nguyen (JX Nippon)

The role of mobile shale in forming fold belt anticlines and hydrocarbon accumulations in Sabah Basin, Malaysia

Subsurface Characterization (Room 2)
Thursday, September 14
5:00 pm

The Sabah basin, located in offshore Sabah, is a well-known oil and gas production area of Malaysia. The thickness of sediments in the Sabah basin reaches up to 12 km in its deepest depocentre. Many of the oil and gas fields are associated with toe-thrust anticlinal structures. Among all the drilled structures, prospects, and leads, it is believed that up to 80% are shale diapir related structures. It is observed that the distinction on seismic between overpressured shale and the effects of gas is often difficult to differentiate in these deepwater structures, as the acoustic velocity of overpressured shale is comparable to gas-saturated formations (as low as 1500–1700 m/sec). This necessitates careful analysis of mobile shale analogues in the vicinity. In general, shale ridges have smooth surfaces, while intrusions exhibit pipe-like morphology. The intrusion of mobile overpressured shale typically causes deformation and fracturing of the surrounding sediments, which may affect the underlying source rock interval, thus facilitating hydrocarbon migration.

In this study, we modelled the movement of shale bodies by assuming a constant shale area during structural deformation and by applying the algorithms for intrusion and fracturing in PetroMod 2DTM software. Two shale facies” including —stable shale and mobile shale—were established for mobility modeling with different physical parameters, such as density, viscosity, frictional angle, and cohesion. During pore pressure evolution, it is noted that when pore fluid pressures reach 80% of lithostatic stress, hydraulic fracturing will occur and fluids will be expelled from stable shale. On the other hand, the light, highly viscous and less frictional angle shale will start to mobilize.

In the latter model, the effects of forces due to Pliocene tectonic inversion were also modeled by adjusting the boundary conditions, including pressure, displacement, and shearing. The modeling results show that the shale mobilization can contribute locally to high pore pressure gradient up to the fracture gradient, resulting in fractures and higher permeability in the vicinity of the mobile shale. The resulting fractures will facilitate fluid flows including hydrocarbon migration both vertically and laterally.

  • B. Nguyen (JX Nippon)

9:00 am

Exhibition Open, Technical Program

10:30 am

Coffee Break

12:30 pm

Cocktail Lunch and Closing Ceremony

2:00 pm

Close

9:00 am Well Construction

Developing an integrated geomechanical model for Clair, North Sea

  • R. Naidu (BP)

Developing an integrated geomechanical model for Clair, North Sea

Well Construction
Friday, September 15
9:00 am

The Clair oilfield is situated on the UK continental shelf (UKCS), 75 km west of the Shetland Islands, in 140 m water depth. Clair Phase 1 development has produced more than 100 million barrels since 2005. Clair Ridge development targets 640 million barrels of recoverable resources and, with an investment of approximately £4.5bn is one of the major projects in the BP portfolio. Hook-up and commissioning of topsides is now underway, with first oil expected in 2018. An appraisal drilling programme in the Clair field to help define a possible third phase of development is also in progress.
Horizontal drilling is one of the key enablers of the Clair project. Some early high-inclination wells during Phase 1 development were adversely impacted by wellbore instability within Cretaceous mudstones overlying the Clair oilfield. Extensive geomechanical analyses had been performed and various models had been built over the years.

The Clair field is a geologically complex structure and analysing various aspects of well planning and life-of-field assessments typically involves multiple tools and approaches by specialists from various sub-disciplines. The challenge of integrating such a diverse team to produce business products, for example a mud weight program for well planning, in a timely manner was recognised considering the time and manpower available in the current climate.

Standardisation of the toolkit using Petrel and Techlog provided the opportunity to integrate various models and develop a fit-for-purpose tool that can also grow with our evolving knowledge to be gained in future years. The best-in-class interpretations by the subsurface team, consisting of geologists, geophysicists, structural geologists, geomechanicists, pore pressure-fracture gradient (PPFG) specialists and reservoir engineers, were integrated to produce a unified geomechanical model that can be used for well planning purposes. Further work to augment our life cycle prediction capabilities is under progress, for example, estimating the impact of depletion on future drillability.

This presentation will describe the approach followed, the technical description of the features used, the model delivered, the lessons learned, and the vision for the future.

Authors: Raja Naidu (Sr. Technical Specialist – Geomechanics) Nigel Last, Distinguished Advisor – Wells

  • R. Naidu (BP)
9:00 am Unconventionals

Thebes formation Unconventional resource assessment, Gulf of Suez, Egypt

  • Z. Elsisi (Gulf of Suez Petroleum Company)
9:00 am Production Operations

Geothermal data management system

  • E. Juliusson (Landsvirkjun)

Geothermal data management system

Production Operations
Friday, September 15
9:00 am

The National Power Company of Iceland’s, Landsvirkjun, role is to maximize the potential yield and value of the natural resources it has been entrusted with, in a sustainable, responsible, and efficient manner. The system used for management of geothermal power production and operations in Landsvirkjun had to be updated to better accommodate the needs of the users that must be able to capture, process, data and visualize it in a convenient way. Schlumberger Software Integrated Solutions (SIS) was selected to implement a geothermal data management system (GDMS), to be configured based on the requirements analysis, technical and calculation method, documentation, and discussions with Landsvirkjun and third parties that collaborate on the decision-making process and analysis of asset operations.

The objectives of the system are to

  • Better monitoring and management of Landsvirkjun geothermal assets
  • Improve logging, maintenance, and quality assurance of data
  • Facilitate employee alertness and overview of data that is being collected
  • Ease access to and analysis of data
  • More efficient reporting from R&D to field operators
  • Simplify data transfer from Landsvirkjun to consultants or research collaborators.

The GDMS solution pulls data from different data sources. Some examples of data types gathered are:

  • Logs: caliper, cement bond, flow (spinner), gamma GU, P/T, neutron NU, dual neutron, spontaneous potential, resistivity, etc.
  • Air quality and weather: air P/T., relative humidity, wind direction and speed, barometric pressure, H2S and SO2, power, etc.
  • Discharge data: water rate from streams
  • Data related to groundwater and from geothermal station: air P/T, barometric pressure, groundwater levels, relative humidity, water temperatures, wellhead P/T
  • Steam transmission data: HP separator Na, gas and pH; LP separator Na and pH, HP separator gas volume
  • Plant power production data: turbine electric power, HP & LP steam and pressure, condenser P and T, cooling tower data, condenser thermal power, turbine thermal and mechanical efficiency
  • Well production and injection data: includes wellhead P and T, barometric P, orifice measurement, two-phase lip, water weir, steam and water tracers, steam and water mass and volume measurement, well connection data, well status, well flow and enthalpy output, well power production output
  • Chemical analysis data: various condensate, gas, steam and water lab analysis, solid sample chemical analysis, measured sample properties, etc.
  • Wellbore schematics: well casings, deviation surveys, feed zones, etc.

Overall, the GDMS allows Landsvirkjun to fulfill its immediate requirements of a solution that is scalable and extensible.

  • E. Juliusson (Landsvirkjun)
9:00 am Field Development Planning

Large scale thermal simulations using INTERSECT

  • G. Darche (Total)

Large scale thermal simulations using INTERSECT

Field Development Planning
Friday, September 15
9:00 am

TOTAL is using, as a partner of the INTERSECT project, the INTERSECT reservoir simulation software for thermal SAGD modeling studies. Thanks to its numerical efficiency and its scalability, we are able to handle different types of complexity in full-field simulations of the SAGD process used for bitumen production.

First, we show that, thanks to INTERSECT, we can manage an accurate multi-component description of the bitumen (five hydrocarbon components) in a one-million-cell model (several SAGD pairs), thus enabling a better modeling of the oil-gas interactions and of the evolution of produced oil quality. Second, we use INTERSECT on a “mega full-field model” (N x 10 million cells), containing several well pads, in order to model interactions of steam chambers between neighboring pads (and not only between adjacent SAGD well pairs), thus enabling us to optimize a full-field SAGD development.

By using fine grids, or a fine PVT description of the fluids, we can highlight local phenomena, local steam breakthroughs, local contacts between adjacent pads, and evolution of the fluid composition in the reservoir and in the production stream. This should help the engineers to better understand the behavior of a SAGD process during production, by enabling more comparisons between production data, local monitoring data, and the simulation results.

These studies are performed by running INTERSECT on a dedicated high-performance computation cluster, taking advantage of the parallel scalability of the simulator by using a large number of individual processors.

We believe this capacity is a breakthrough, as compared to conventional thermal simulations, because it will enable reservoir engineers to model SAGD physical mechanisms which up to now, were simplified or even unpredicted. Typically, reservoir engineers should now be able to run full-field SAGD simulations in order to optimize the management of individual well pads when the development reaches a mature production level, implying operating different pads simultaneously. Furthermore, it should also give a better insight into more complex processes, such as SAGD using complex wells, or SAGD with additives (dry gas, solvents, etc.), which currently are mostly operated as pilots. A better analysis of these pilots, with more advanced simulation runs, will enable getting more valuable information before deciding to extend this new technology at a field-scale level.

  • G. Darche (Total)
9:00 am Business Tranformation

A decade of Ocean: Delivering proprietary technology for a major enterprise

  • V. O’Connor (PDS)

A decade of Ocean: Delivering proprietary technology for a major enterprise

Business Tranformation
Friday, September 15
9:00 am

PDS has a long track record of working with the Ocean software development framework, delivering more than 200 proprietary plug-ins over the last ten years, initially for Petrel and, subsequently, Techlog, for global deployment in Shells' complex enterprise environment.

In this presentation, we share our experience tackling some of the major challenges we see for any enterprise using the Ocean framework to support the codification and integration of their proprietary workflows.

Effective product lifecycle management, which responds to progress in vendor technology, demands a structured approach to prototyping, deployment, ongoing support, maintenance as a vendor technology evolves, and decommissioning. Rigorous release management, including the development of internal Ocean stores with advanced configuration processes suitable for the organizations' transition to cloud, is critical, regardless of where the technology is positioned between seismic processing and production optimization. This enables rapid deployment to key users ahead of company-wide deployment and access to the right versions when using virtual machines.

In our experience, integration is also important in an enterprise environment. Ensuring stability within existing and future application landscapes, and our use of componentization has been fruitful. In addition, the support model we have developed for internal workflow organizations and research teams, applying the innovative technology we deliver across the entire organization (or team), has also paid significant dividends.

Looking ahead to the future, there are many opportunities to capitalize on scalable Cloud architectures and the incorporation of machine-learning approaches. Just two of the areas PDS is currently exploring are the development of new web-based plug-in architectures to ensure portability of major vendor technology to the Cloud, along with proactive collaboration with leading academic institutions to help them maximize their research impact.

  • V. O’Connor (PDS)
9:00 am Data and Analytics

Integrated core data management in Kuwait Oil Company

  • H. Al-Aradi (Kuwait Oil Company)

Integrated core data management in Kuwait Oil Company

Data and Analytics
Friday, September 15
9:00 am

Core is one of the main data throughout the lifecycle of subsurface activities within exploration, development, and production. Significant increase of E&P activities would immediately grow the volume of core data. This requires comprehensive data management, especially to have high-quality and accurate data and provide effective workflows and consistent and better accessibility.

Core reports are loaded into eSearch as physical assets and are accessible to users, while the inventory of physical core samples is stored in an Excel file and it has no association with core reports. With no central database of digital core samples, analysis, and interpretation, users have to read entire core reports or browse through the content of an entire CD and shared drive to look for relevant core data. This is very time consuming and prone to errors. In terms of repatriation of physical core, KOC may not have an effective control on physical core samples that remain with the vendor and may not be adequately inventoried. This means the samples may be missing, damaged, or destroyed without sufficient record being kept.

KOC has a vision to consolidate and enhance the existing core data management process and technology and to implement a comprehensive corporate-wide core data management workflow. Core data management has been performed by implementing an inventory of KOC core data in centralized repository with physical cores and reports in eSearch and digital data in ProSource, association of core samples and reports, and integration between eSearch and ProSource. This ensures data availability and data quality improvement throughout all departments, enhances current core data management, and improves core data delivery to the end users by providing proper workflow and technology.

There are several major business benefits arising:

  • One-stop shop for all core-related data. Access to integrated physical and digital core data from a single interface.
  • Accessibility improvements. Comprehensive solution to provide high-quality and accurate data, effective workflows, and consistent and better accessibility.
  • Reduce searching and tracking time, increase the usage of core data, and allow users to have more time for interpretation and analysis.
  • Single control over core data to allow full inventory of assets to be maintained. Improve core data delivery to the end users.
  • Long-term protection of digital assets and possibility to maintain a full disaster recovery system.

  • H. Al-Aradi (Kuwait Oil Company)
9:00 am Subsurface Characterization (Room 1)

Application of process based stratigraphic modeling: Clastic and carbonate case studies

  • M. P. Suess (Wintershall)

Application of process based stratigraphic modeling: Clastic and carbonate case studies

Subsurface Characterization (Room 1)
Friday, September 15
9:00 am

Process-based stratigraphic modeling is a key technology to quantitatively predict the sedimentation of stratigraphic sequences at regional and reservoir scale (Paola 2000; Burgess 2012). It is suitable for regional basin studies, as well as high-resolution studies of the reservoir occurrence, architecture, and quality.

The technology is based on the concept of mass balance and, as such, an extension of classic basin analysis as applied in petroleum systems modeling. However, while in the latter, the sedimentary deposition is not treated as a specific dynamic process, sedimentary processes and their impact on sedimentary bodies are in the focus of process-based stratigraphic modeling. This includes both the process of sediment generation by erosion or precipitation, as well as the transport and deposition.

The basic technology has been developed for many years. Early applications started out in 2D and later developed in 3D (Tetzlaf and Harbough 1989; Shafie and Madon 2008). Today the modeled processes are ever closer to reality, based on incorporation of realistic physical approximation of transport and sediment generation. Not only processes like erosion and transport in deep and shallow marine seas, but also transport by waves, steady and unsteady currents, and as well as carbonate growth can be modelled in spatial and stratigraphic-meaningful resolution (see discussions in Seared et al. 2014). The now-available sediment transport modeling techniques allow for the prediction of grain sizes and porosity. Coupled with simple models of compaction and diagenesis, the quality of reservoirs can be forecasted.

However, process-based stratigraphic modeling is still not a routine methodology in exploration. One of the main challenges of process-based stratigraphic modeling is the parametrization and calibration of the physical processes (Falivene et al. 2014). To modelers, much of the needed input, like regional paleobathymetry and topography, sediment input rates, or carbonate growth rates, appears usually to be highly uncertain when going back in Earth history. Many other parameters are simply not easily available to modelers, as they represent physical variables, which can only be obtained from analogue dynamic sedimentary transport experiments or from physical measurements in natural sedimentary environments.

Integrated environments, like Petrel support the interpretation and calculation of important input variables like sediment masses, paleotopography, and subsidence. The modeling results can be directly compared to stratigraphic subsurface data (like seismic and wells) and can be transferred into reservoir models. Improvements in algorithms, combined with the availability of increased computer power allows today, to model the evolution of full stratigraphic sequences at high resolution in reasonable time. By the generation of scripted uncertainty workflows, parameter sensitivities can be studied and optimization methods can be applied to obtain a fit to constraining data (e.g., Cross and Lessenger 1999; Falivene et al. 2014).

Wintershall, in collaboration with the University of Tuebingen and Schlumberger Research, is investigating the application of a new stratigraphic simulation tool (GPM), developed by Schlumberger Research, and a related Petrel plug-in in the frame of case studies ranging from shallow marine clastic and carbonate depositional environments to deep sea turbidite environments on active and passive continental margins.

  • M. P. Suess (Wintershall)
9:00 am Subsurface Characterization (Room 2)

Improved attribute analysis using volume based structural models

  • M. Gidding (Third i Geoscience)

Improved attribute analysis using volume based structural models

Subsurface Characterization (Room 2)
Friday, September 15
9:00 am

The Western Sarawak Basin of Malaysia features a Miocene sequence of shallow marine and lower coastal plain clastics. The focus of the study was the Cycle V clastic sequence. The top of this sequence is a regional unconformity and the predominant reservoir/seal pair in the area. The exploration blocks under review are in a very high CO2 province and all traps at top Cycle V have CO2 concentrations removing them from commercial consideration. There are, however, several sweet gas intersections intra Cycle V in thin sands. The aim of the study was to determine the distribution and geomorphology of these sands.

Due to the combined effects of the large gas accumulation and its associated CO2 diagenetic halo, part of the study area features significant degradation in signal quality of the 3D seismic data. To deliver surfaces upon which reasonable attribute work could proceed, Petrel’s volume-based modeling (VBM) approach was used to reconstruct continuous surfaces in areas of poor data.

The talk outlines the basic tenants of VBM, addresses the challenges of the dataset under review, and discusses the results of the modelling. In doing so, it covers some of the processes and pitfalls that a user must consider when undertaking a complex modeling study. Finally, some attribute mapping based on the VBM based surfaces is presented.

  • M. Gidding (Third i Geoscience)
9:00 am Eurasia

The digital era for E&P: efficiency improvements and new ways of working in our industry

  • G. Karnaukhov (Schlumberger)
9:10 am Eurasia

Integrated thermodynamic reservoir-to-surface modeling: the modern tool for optimizing the cyclic steam stimulation recovery process

  • R. Khaliulin (Rosneft SakhalinNIPImorneft)
9:30 am Well Construction

Lateral landing and completion

  • I. Mikhaltseva (Schlumberger)
9:30 am Unconventionals

Lateral landing and completion

9:30 am Production Operations

One team, one objective: production enhancement of Hassi Messaoud field, Algeria

  • A. Nouacer (Sonatrach DP)
  • D. Neghmouche Ali (Sonatrach DP)

One team, one objective: production enhancement of Hassi Messaoud field, Algeria

Production Operations
Friday, September 15
9:30 am

The giant Hassi Messaoud field (HMD), operated by Sonatrach is one of the largest mature fields in the world. It was discovered in 1957 and put on production in 1958. More than 1500 wells have been drilled in the field so far.

Objective
With the objective to increase the production in the field, a joint project (TAO) between Sonatrach DP and Schlumberger SIS has been put in place. With the motto “identify, analyze and solve”, the TAO team works collaboratively with all DP departments and Schlumberger segments to assure a high quality of the execution and to introduce and adopt new technology and products to the field.

Full integrated approach
A full integrated approach (from study to implementation) has been applied which includes: Diagnose the production decline issues, propose appropriate interventions, follow up on the operations execution and analyze the results.

HMD reservoir (Cambrian sandstone) represents a wide range of heterogeneity, combined with severe flow assurance issues requiring a well-by-well analysis for any production enhancement interventions. Depending on the issue the recommendations can be: Clean out, reformat treatment, acid treatment, gas lift optimization, perforations, hydraulic fracturing, multistage completion, short radius re-entry, etc. Following up on the execution of the operations gives a great opportunity to analyze the efficiency of the recommendations and take appropriate actions.

Technologies and Results
Technologies like (HiWay, Multistage Completion, CT ACTive, Saltel patches, etc.), electrical submersible pumps (ESP), new salt and asphaltene inhibitors, and new software (OLGA and Avocet, in addition to OFM, Petrel, Techlog, PIPESIM, and ECLIPSE used on a daily basis) have been implemented.

Two ESPs have been installed for the first time in the field based on the candidate selection by the TAO team, which have given very good results. A production increase of 2 m3/h for the first well and 6 m3/h for the second demonstrate the efficiency of joint work between the two companies. A detailed transient gas lift study followed by the deployment of real-time well surveillance (RTWS) have been put in place. Pipeline network modelling using OLGA software, applied first in two separate manifolds and now in progress for the northern part of the field, is another promising direction to identify, analyze, and solve the issues of production fluctuation and back-pressure in the pipelines.

The project is in progress and large number of wells require advanced analysis and technologies for production enhancement.

Note. Prepared by Ammar Nouacer (SH), Djilani Neghmouche (SH), and Alban Collaku (Schlumberger)

  • A. Nouacer (Sonatrach DP)
  • D. Neghmouche Ali (Sonatrach DP)
9:30 am Field Development Planning

Addressing reservoir characterization challenges of SAMA EOR pilot in North Kuwait

  • S. Tiwari (Kuwait Oil Company)

Addressing reservoir characterization challenges of SAMA EOR pilot in North Kuwait

Field Development Planning
Friday, September 15
9:30 am

The Sabriyah Mauddud (SAMA) EOR pilot is considered as one of the first pilots of its kind in Kuwait. Based on simulation work and laboratory experiments, alkali surfactant polymer (ASP) is expected to be the best EOR agent to achieve the production targets. The goal is to evaluate the sweep efficiency of sea water then determine the additional recovery by utilizing ASP flooding in Mauddud carbonate. This formation is currently undergoing field-wide sea water injection. Due to the high heterogeneity of SAMA, KOC decided to study the connectivity, permeability anisotropy, and fluid properties for all the drilled EOR pilot wells. The study will allow KOC to understand the small-scale heterogeneities that are critical to EOR success and obtain information to help plan a full-scale commercial operation. The pilot consists of 7 wells: 4 injectors, one producer and 2 observations. The 4 injectors and one producer are arranged in a 5-spot pattern.

The logging was aimed at addressing multiple reservoir evaluation challenges. The first challenge is the saturation evaluation. Archie’s parameters carried high uncertainty due to the possibility of wettability alteration (variation in saturation exponent) as well as variability of the texture of the rock (variation in cementation exponent). In addition, due to the nearby sea water injection, the formation water salinity is variable. The second challenging aspect in this evaluation was the acquisition of an extensive sampling program aimed at characterizing the mobile fluids fractions in the formation in relatively tight carbonate layers (~ 0.1-10 md/cP). In addition to the reservoir complexity, the selected EOR methodology is the first of its kind to be implemented in a carbonate reservoir in the region. The cost for this project is very high; therefore, this study is extremely important in developing mitigation plans, reducing potential risks, and estimating injectivity.

To address the petrophysical challenge, resistivity-independent measurements (Dielectric Scanner and MR Scanner) were acquired. An innovative, unique, multi-well workflow was applied to extract the Archie parameters (cementation and saturation exponents) from the Dielectric Scanner water-phase tortuosity measurement, in combination with multi-well rock typing based on NMR data from MR Scanner. This resulted in a more accurate evaluation of the water saturation, which is greatly affected by the saturation exponent due to the observed mixed-wet reservoir condition. Those measurements confirmed the water saturation in the flushed zone, providing an upper limit for reservoir water saturation and allowing to constrain the resistivity-based evaluation. Lab analysis of the water acquired during sampling in producer well P showed formation water salinity varied between 66 ppk and 112 ppk.

To address the sampling challenge, a unique mirror toolstring MDT configuration was utilized to be able to sample while the well was taking losses. Without this technique, sampling would not have been possible in those wells. Five to eight stations were acquired in each well, with a total of 54 PVT-quality samples for the 6 wells. Vertical interference testing data was also acquired at 5 stations in injector well ‘I4’ and 4 stations in observation well ‘O1 to determine permeability anisotropy and vertical connectivity. The in-situ KrPc analysis performed in well I4 also helped reduce uncertainty regarding the reservoir wettability conditions. Injector well I4 is the first well in North Kuwait where this technique was applied. The analysis will also be performed for observation well ‘O1’ data.

  • S. Tiwari (Kuwait Oil Company)
9:30 am Business Transformation

A New Era of Automated E&P Workflows

  • A. Shtuka (Seisquare)
9:30 am Data and Analytics

Reservoir management in the age of big data

  • TC Sandø (Resoptima)

Reservoir management in the age of big data

Data and Analytics
Friday, September 15
9:30 am

Every year, E&P companies invest millions of dollars in reservoir modelling efforts to improve their understanding of the future behavior of their fields. With a traditional approach to reservoir modelling, this is often a costly and time-consuming process, where it can take months or years to integrate new data from newly drilled wells, seismic surveys, or production. In this presentation, we will demonstrate how ResX, together with Petrel and ECLIPSE/INTERSECT, can help subsurface teams build reliable reservoir models in the age of big data – faster.

We will show how current challenges can be addressed using an ensemble-based reservoir modelling solution that

  • Builds reliable reservoir models using data, reservoir physics, and the know-how of the subsurface team—using repeatable modelling workflows
  • Generates multiple models that capture and propagates uncertainties, from static data collection and interpretation to flow simulation and dynamic data conditioning
  • Generates reliable models that increase the understanding of the reservoir and help the subsurface teams maximize the potential of their reservoir management efforts.

We will demonstrate how ResX, together with Petrel and ECLIPSE/INTERSECT, helps E&P companies save time and money on fields world-wide today by going through the highlights of two case studies.

  • TC Sandø (Resoptima)
9:30 am Subsurface Characterization (Room 1)

Schlumberger High-end technologies in Eastern SIberia. A Gazpromneft Angara-SIS case study.

  • L. Shakirzyanov (GPN Angara)

Schlumberger High-end technologies in Eastern SIberia. A Gazpromneft Angara-SIS case study.

Subsurface Characterization (Room 1)
Friday, September 15
9:30 am

Vakunay project has had great visibility and importance for Gazpromneft, WesternGeco, and Schlumberger overall. Most recent Schlumberger high-end technologies, such as UniQ seismic acquisition, Well-Driven Seismic processing, sophisticated Schlumberger wireline tools, rock physics analysis with stochastic AVA-inversion, and Petrel with the Studio environment as a main working environment were used for its execution.

Vakunay oil field is an exploration asset of Gazpromneft and has strategic value not only for its operator, but also for exploration of the whole East Siberian region. This area is considered as one of the highest hydrocarbon potential basins worldwide, characterized by extremely complex geological conditions and not well discovered yet. Massive salt and flood basalt layers with a combination of high-amplitude thrust faults in upper interval prevent obtaining a proper seismic image and significantly impede exploration and development of oil and gas fields in this area.

The main goal of the project was to find the most effective methodology of reservoir properties forecasting in Eastern Siberia and perform sweet spot analysis for exploration drilling. This became possible due to integration of high-end technologies and collaborative work of more than 20 petro-technical experts of the Gazpromneft and Schlumberger teams.

This project includes the full exploration cycle, which started from acquisition of the first UniQ seismic data in Russia and finalizing with simultaneous stochastic and deterministic AVA-inversions for production zones forecast. Comprehensive analysis of available geological, petrophysical, seismic, and production data allowed building a conceptual geological model and mapping best reservoir zones for 5 carbonate and 2 clastic reservoirs.

Results of this study have significantly increased understanding of the oilfield’s geology and allowed planning further exploration drilling based on the new detailed geological model.

  • L. Shakirzyanov (GPN Angara)
9:30 am Subsurface Characterization (Room 2)

Identification and quantification of thinly bedded low resistivity pay in Peninsula, Malaysia

  • A. A. Hutajulu (PETRONAS)

Identification and quantification of thinly bedded low resistivity pay in Peninsula, Malaysia

Subsurface Characterization (Room 2)
Friday, September 15
9:30 am

In some fields in Peninsula Malaysia, there are reservoirs that have thin laminations of sand and shale, which contain hydrocarbons, but either not identified as hydrocarbon bearing, or hydrocarbon-in-place is not properly quantified. A low-resistivity reservoir is a pay zone that has relatively low resistivity and thus is calculated wet using conventional well log evaluation. A low-contrast reservoir is a pay zone that has low resistivity contrast between sand and adjacent shale. The effect of both phenomena is that the apparent formation resistivity is dramatically reduced resulting in underestimation of calculated hydrocarbon saturation and volume of hydrocarbon-in-place. A number of factors have been found to act on measurements made by well logging instruments to produce low resistivity and/or low contrast, yet economically productive formations. The factors include bed thickness, grain size, mineralogy, structural dip, clay distribution, and water salinity and any combination of the above. Often a combination of interrelated factors causes the well logging instrument to measure lower resistivity than would ordinarily be expected inside an economically productive formation. During data acquisition in wells using conventional logging tools, the actual resistivity of such thin-bedded pay zones are not measured. This is because of the poor vertical resolution of the tools (compared to the thickness of laminations).

Previously, the interpretation methods relied on conventional formation evaluation, which largely bypassed and ignored the additional hydrocarbon potential associated with thin-bedded reservoirs. This motivated Petronas to pursue the low-resistivity and/or low-contrast study with an emphasis on quantification of hydrocarbon saturation. In this study, a Thomas-Stieber approach is performed to define the properties of clean sand, pure shale, and the fluid. The Hagiwara macroscopic anisotropy approach is used to do the resistivity modeling. The resistivity model uses RTSand and laminated shale resistivity as inputs to calculate the horizontal resistivity (Rh) and vertical resistivity (Rv) and followed by saturation calculation using the Waxman-Smitts method.

It is observed that the hydrocarbon saturation obtained from the analysis improved. It represents more closely the formation hydrocarbon saturations in thin-bedded reservoirs. The results are validated by perforating the zone of interest and it is producing 600 oil bbl/d and 0.2 mmscf/d. This approach is encouraging to be used to the wells with similar geological facies to optimize the resources assessment.

  • A. A. Hutajulu (PETRONAS)
9:40 am Eurasia

From technology adoption to a multiyear collaboration—uniquely sized 3D geomechanics modeling solves drilling and completion challenges, East Siberia, Russia

  • M. Lushev (Gazprom Geologorazvedka)
10:00 am Well Construction

Wintershall’s new software initiative aims to improve decision-making during planning and operations of wells

  • J. Schamp (Wintershall)

Wintershall’s new software initiative aims to improve decision-making during planning and operations of wells

Well Construction
Friday, September 15
10:00 am

Wintershall’s Well Engineering Best Practice Group had the goal to enhance the software portfolio used companywide for drilling engineering in order to increase planning accuracy, optimize well control procedures, improve operational decision support, complement drilling data life cycle management, and analyze and optimize drilling operations.

Several different pieces of software will be implemented centrally for all Operating Companies (OpCos) and their various drill sites, and will set a new Wintershall E&P software standards, complementing the existing software portfolio.

Permanent surveillance and in-depth understanding of the dynamic well parameters are vital to every drilling operation. Especially, the ability to predict and control the pressures, to foresee and mitigate any potential well control issue and to be well prepared in case of a major incident is crucial to ensure prudent, safe, and efficient operations.

To establish compliance with the requirements stipulated in the “EU Directive 2013/30EU on safety of offshore oil and gas operations” – which became effective on July 19th 2015 – and follow the agreed real-time integrated drilling simulation recommendations of the quoted technology study, Wintershall aims to enhance its drilling engineering application portfolio to support dynamic drilling simulation using Schlumberger’s solution: Drillbench.

This will be part of a set of software with high influence on the safety and integrity of drilling operations and which are not fully covered by the current software portfolio. They complement and complete the rather complex, interdisciplinary workflows used in the well engineering planning, execution, and evaluation process documented in the Wintershall Well Engineering Management System (WEMS), which is the basis for all Wintershall well operations.

The project was approved by BASF IT support in December 2015. Having received the IT approval, final contract negotiations, procurement of the software licenses, and implementation at all drilling offices and well sites was scheduled for the 1st quarter of 2016. An initial training of the Schlumberger Drillbench simulation software was performed in the second week of December 2015.

  • J. Schamp (Wintershall)
10:00 am Unconventionals

Advanced stimulated rock volume simulation workflow to support development of unconventional play

  • S. Vidal-Gilbert (Total)

Advanced stimulated rock volume simulation workflow to support development of unconventional play

Unconventionals
Friday, September 15
10:00 am

Shales are heterogeneous rocks characterized by very low permeability and because of this low matrix permeability, hydraulic fracturing is a requirement to achieve economic developments. Stimulation of shales is performed by creating a stimulated rock volume (SRV), where hydraulically induced fractures connect with preexisting natural fractures. The SRV efficiency will be influenced by the SRV geometry, which describes the potential for creating and maintaining open fractures in regions where resource is high. Under these circumstances, the ability to evaluate the extent of the stimulated volumes following a hydraulic fracturing treatment becomes crucial.

Traditionally, the most widely used hydraulic fracturing approaches include semi-analytical calculations simplifying the fracturing system to a planar feature propagating symmetrically away from the injection section. In most of the cases, geomechanical inputs (i.e., elastic properties, minimum horizontal stress profile at injection point, and reservoir pressure) are identified at initial reservoir condition and left unchanged upon subsequent fracturing treatments, such as multi-stage hydraulic fracturing, refracturing, and fracturing of neighboring wells in the same well pad. This leads unavoidably to uncertainty in provided inputs to hydraulic fracturing design and, consequently, to unpredictable effectiveness of treatments. An appropriate approach to the problem should include specific features, such as influence of natural fractures, changes in stresses due to fracturing and subsequent production, and model calibration based on microseismic monitoring.

To address some of the issues involved, a novel seismic-to-simulation workflow in Petrel Kinetix Shale embracing hydraulic fracturing modelling, reservoir geomechanics modelling (VISAGE *) and production modelling (INTERSECT) has been applied. The workflow leverages various state-of-the-art technologies for unlocking unconventional reserves, amongst these are horizontal drilling, multi-stage hydraulic fracturing, complex fracture network modelling, geomechanical coupling, and microseismic events prediction. This work describes the implementation of the general workflow from single-well characterization to reservoir-scale modelling applied to achieve successful stimulation treatments. Results are compared with in situ observations from actual treatments and microseismic monitoring. The work also highlights the importance of data integration at various scales in order to address fundamental aspects related to well placement for hydraulic fracturing, effects of fracturing sequences, and wellbore stability during drilling as a consequence of changes induced by fracturing and production.

  • S. Vidal-Gilbert (Total)
10:00 am Production Operations

From field operations to economics: Breaking the barriers. Next level of integration

  • A. Mukanov (PetroKazakhstan Kumkol Resources JSC)
10:00 am Field Development Planning

PICO Optimize Well Placement Decisions in the Mature Rudeis Field

  • A. Ewais (Pico)
10:00 am Business Transformation

Development of long-term training plan using matched competency assessment and discipline training roadmaps: Case study from Kuwait

  • G. Ahmed (Kuwait Oil Company)

Development of long-term training plan using matched competency assessment and discipline training roadmaps: Case study from Kuwait

Business Transformation
Friday, September 15
10:00 am

The Exploration Group of Kuwait Oil Company (KOC) has initiated and developed Discipline Training Roadmaps (DTRs) in order to expand the specialized technical professions of the Group employees. The program is designed for employees in the first 10 years of their career path in alignment with the Company competency matrix and the future professions and skills required to achieve the Company 2030 strategic plan. This requires the essential design of further sub-competencies, which resulted in more detailed descriptions of the newly developed programs.

The years and eras of finding large hydrocarbon fields no longer exist; geoscientists and engineers are facing challenges to discover and produce hydrocarbons, and the very deep targets, size, high temperature and pressure, very deep water depth, climate, etc. These challenges require the development and application of high-end technology. A key limitation for most of the oil companies, in particular in the Middle East, is the limitations of the highly skilled and trained professionals who are capable of understanding and applying the evolved technologies.

The proposed developed program takes into consideration the role of technology in the future of the oil industry, which focuses on the final phase for duration of 10 years of the employee’s career development. In order to progress the specialized technical professional requirements needed by the company, sub-competencies have been developed for the discipline specific competency resulted in further detailed descriptions of the DTRs.

The second phase of this project is the individual competency assessments of selected 100 of the Exploration Group technical staff for six job grade levels and from 0 to 20 years of experience. The assessments will use the DTRs to provide detailed and oriented individual training plans for the staff in addition to an analysis of major strengths and weaknesses by discipline.

The third phase is the individual assessments of the remaining technical staff in the Group, with the assessments being validated by the Group senior staff. This was conducted in conjunction with NExT, who provided further support for the KOC assessors. This phase has the added value of allowing KOC to conduct future assessments using their own resources.

This paper describes the motivation, development and implementation of the proposed model within KOC and investment in improving employees’ professions and skills, which are considered the most significant asset for achieving the company strategic objectives.

Note. Authors: Ghada Ahmed, Kuwait Oil Company – Exploration Group (Presenter), Mohammed Dawwas Al-Ajmi, (Exploration Group Manager), Laurence Darmon, Schlumberger NExT

  • G. Ahmed (Kuwait Oil Company)
10:00 am Data and Analytics

Developments in automation and machine learning - realizing the value within a National Data Collection through data analytics

  • P. Coles (CDA)
10:00 am Subsurface Characterization (Room 1)

Decision making without seismic or well data: Modeling scenarios and how they can influence E&P

  • L. Truelove (Schlumberger)
10:00 am Subsurface Characterization (Room 2)

The geomodeling of fan-delta reservoir with clastics and carbonate in Bohai Bay

  • Z. Y. Kun (CNOOC)

The geomodeling of fan-delta reservoir with clastics and carbonate in Bohai Bay

Subsurface Characterization (Room 2)
Friday, September 15
10:00 am

1. Research Background

The fan delta reservoir of the Shijiutuo area in Bohai Bay, of China, has huge potential oil and gas resources. For Q oilfield belonging to CNOOC, which is located in the north of Shijiutuo uplift, the drilling data reveals that the reservoir has serious internal heterogeneity and vertical complex lithology distribution because of the clastics and carbonate mixed deposition. Overall, the reservoir shows low porosity and super-low permeability and the thickness of the reservoir is large but with quick lateral change. Meanwhile, there are only two evaluation wells, with larger well spacing in the oilfield. Limited by the number of evaluation wells in offshore oil field and low-quality seismic data in exploration and evaluation stage, it is difficult to understand the reservoir well. But in the field development phase, if only using the conventional regular well pattern to develop the oilfield, large uncertainties will be inevitable. Thus, using the geologic model to characterize the good reservoir spatial distribution quantitatively will effectively reduce the development risk of reservoir in this stage.

2. Key Combination of Technologies

How to take advantage of limited well data and low-quality seismic data to characterize reservoir spatial distribution reasonably is the difficulty for geomodeling of such a thick, ultra-low permeability reservoir with complex lithology changes.

Firstly, adopt the element capture spectroscopy logging to identify complex reservoir lithology and then combine with the nuclear magnetic resonance logging to optimize different lithological interpretation of reservoir permeability. Meanwhile, by taking lithology and physical properties into account, divide the reservoir into high, medium, and low-quality lithofacies. This classification is based on geological law and makes the reservoir physical properties more accurate.

Combine seismic attribute slice analysis with lithology distribution of wells to figure out different fan deltas and build the fine-scale stratigraphic framework to establish the structural model. Then, in the stratigraphic framework, predict fan distribution range by using seismic multi-attribute analysis technology to establish the facies model via the deterministic modeling method.

In the facies model, the lithofacies model is built by sequential indicator stochastic simulation method. Using the lithofacies model as a constraint, the physical properties of the reservoir are simulated by sequential Gaussian stochastic simulation method.

3. Application Effect

The technology flow is realized by Petrel, and the spatial distribution features of the complex lithologic reservoir is characterized reasonably. The established geological model not only ensured the isochronous, but also complete the subdivision of the reservoirs, and makes the high-quality reservoir distribution clear. Application of the integration of multi-level facies constraints geological modeling method, improves reservoir prediction accuracy of complex lithology in Paleogene at the exploration and evaluation stage with limited wells only.

  • Z. Y. Kun (CNOOC)
10:10 am Eurasia

Advanced Joint Simulation of Reservoir and Multiphase Fluid Flow in a Horizontal Well with Inflow Control: A Korchaghin Oil Rim Case Study, Caspian Sea

  • I. Sannikov (Lukoil-Engineering)
10:30 am

Coffee Break

11:00 am Well Construction

Utilization of Schlumberger Techlog software for an improved geological understanding of drilling fluid losses and top seal effectiveness within a key UK continental shelf regional stratigraphic marker

  • D. Watson (University of Aberdeen)

Utilization of Schlumberger Techlog software for an improved geological understanding of drilling fluid losses and top seal effectiveness within a key UK continental shelf regional stratigraphic marker

Well Construction
Friday, September 15
11:00 am

The drilling of smectite-rich shales has historically been associated with a number of operational issues. Smectite often swells in contact with water-based mud, leading to problems such as bit balling, ballooning, and, ultimately, wellbore instability. Thick successions are common in basins with drainage from large continents, such as the Gulf of Mexico, but can also be the alteration product of volcanic ashes. One notable succession in the offshore basins of Northwest Europe is the Balder Formation, a prominent, regional stratigraphic marker composed of interbedded shales and tuffs, the latter a product of explosive volcanic eruptions as the proto-North Atlantic Ocean was flooded in the Eocene.

This work focuses on drilling issues associated with the Balder in the Faroe-Shetland Basin, in particular, an intra-basinal high known as the Corona Ridge, the location of the 250 MMBBL Rosebank Field. Here, mud losses (~ 40 bbl/hr) are commonly encountered in the Balder Formation, and drilling dynamics are poorly understood. Using the dedicated Pore Pressure suite in Techlog, we investigated the nature of these mud losses by plotting the geomechanical properties of the Balder from these wells and found that the ECD did not exceed the fracture gradient and that thief zones within the Balder Formation are a product of natural, not fracture induced, permeability.

Using Techlog, we have for the first time, integrated cross-domain workflows to characterize these formations both petrophysically and mechanically, and, in doing so, constrained a geological explanation for this permeability. In a succession that is otherwise thick, laterally extensive and lends itself to being an effective top seal, understanding this complexity has a direct impact on regional understanding and establish best drilling practice to minimize NPT.

The Techlog Geomechanics module has allowed the comparison of petrophysical properties of the Balder Formation where losses occur along the Corona Ridge, with wells drilled through the Balder with no drilling issues in the Bressay discovery. A major difference between the two settings is that the Corona Ridge anticline formed from regional horizontal stress compared to the differential compaction which formed the Bressay anticline.

We propose that the Corona Ridge inversion event likely manifested in horizontal stresses that exceeded the fracture gradient of the Balder, which then acted as thief zones during drilling. This horizontal stress, however, was not sufficient to exceed the fracture gradient of the far stronger basaltic lava top seals below.

  • D. Watson (University of Aberdeen)
11:00 am Unconventionals

Microseismic Monitoring of Hydraulic Fracture Stimulations in Unconventional Reservoirs

  • J. Calvez (Schlumberger)
11:00 am Production Operations

Getting smarter and productive with real time surveillance system to optimize artificial lift system and production management of PERTAMINA E&P’s Asset-5 BrownField

  • A. Haribowo (Pertamina)

Getting smarter and productive with real time surveillance system to optimize artificial lift system and production management of PERTAMINA E&P’s Asset-5 BrownField

Production Operations
Friday, September 15
11:00 am

As a mature field and located in the onshore Mahakam Delta area of south east Kalimantan, Sangasanga field has a challenge to optimize the oil production with a high response time in the remote and scattered well location. The common operational issues, including power supply and well limitations, can have negative impact on the ESP run-life, dominantly caused by excessive trips and shutdowns. Additionally, such trips will result in lengthy downtimes due to the remoteness of the wells. On the production side, these trips will ultimately have a major effect on production target, needs time to get the well back on line after the problem is observed and checked. A real-time surveillance system is an answer that offers delivery of better lift system and production performance using real-time measurements. It combines the latest in downhole sensors and the data is transmitted in real-time to provide 24/7 surveillance, which allows the opportunity for optimization of the artificial lift system and production management. Operational data can then be viewed on demand and updated automatically as well as visualized together with the streamed data anywhere and anytime.

As a result of the real-time implementation, a big improvement in response time has been seen; ESP wells connected to real-time monitoring and surveillance systems provide less shut downs because of proactive responses and early detection of incidents. The notification alarms together with pro-active remedial action can minimize the trips. This situation has direct impact on extending ESP run life and influences the activities of the operational team to manage and gain more oil production in Sangasanga field. Moreover, to have integrated production management and advanced well analysis, the real-time surveillance data has been processed and analyzed by using both the OFM and PIPESIM software; then; the ESP executions were remotely adjusted by the real-time surveillance system.

  • A. Haribowo (Pertamina)
11:00 am Field Development Planning

Fine scale modeling of huge carbonate gas condensate field using high resolution reservoir simulator

  • K. Baigazin (Karachaganak Petroleum Operating B. V.)
11:00 am Business Transformation

Petrel Guru: from geological expertise automation to prompt scientific methodological assistance

  • R. Faizov (Gazprom Neft)

Petrel Guru: from geological expertise automation to prompt scientific methodological assistance

Business Transformation
Friday, September 15
11:00 am

The quality of model-based decisions on exploration and field development relies on the quality of the 3D geological model, which shall be estimated and tracked. Some oil and gas companies developed their own methodology and requirements for 3D model QC, based on set of model parameters, maps, and reports. In Gazprom Neft such approach resulted in implementation of “3D model passport” creation requirement for every 3D model. 

As a rule, a “3D model passport” contains the following data: 

  • Overview 
  • Statistical comparison of well data and geological model outputs in spreadsheet and graphical formats
  • Stylized in accordance with requirements geological cross-sections and suites of maps, which are used as a trend for modeling or plotted as a modeling output 
  • Reserves estimation and uncertainty analysis

Initial experience with starting implementation of “3D model passport” shows that the processes of manual 3D model quality check and further report preparation is time consuming: normally it can take up to 3 working days. Furthermore, report preparation procedures are not free of human errors. It must be separately noted that users usually do not have a quick access to the “Passport” template. Such issues could negatively impact success of mainstream usage of “3D model passport

This paper describes a “3D model passport automated preparation” workflow that was developed based on Petrel Guru. The workflow provides an opportunity to automate geological 3D model passport preparation based on the approved template of Gazprom Neft. Use of this workflow shows real advantages of automation and standardization

  1. Reporting procedures time was cut by 88 to 96%. Automated report generation takes 1 to 2 hours for the initial execution and less than 1 hour for the re-execution.
  2. Standardization of the procedure and minimizing of the “human factor”. Users just need to specify “input 3D model” to run calculations and report generation in accordance with uniform requirements.
  3. Workflow flexibility. Each oil field differs in geological complexity and degree of geologic uncertainty. Advanced Petrel users, who have experience with Workflow Editor, are able to customize and extend workflow.

As an additional topic, the paper addresses change management and integration of new workflows to company processes.  To address these issues in Gazprom Neft, a corporate knowledge management system was created based on Petrel Guru. Currently, it has a significant amount of structured information, containing best practices and corporate guidelines with quick access. The paper demonstrates additional capabilities of Guru to organize local content connected to 3D geological modeling and other areas of knowledge.

  • R. Faizov (Gazprom Neft)
11:00 am Data and Analytics

A successful case study of a collaborative and productive environment empowered by SIS Technologies, DIAVAZ Mexico

  • S. Dalessio (DIAVAZ Mexico)

A successful case study of a collaborative and productive environment empowered by SIS Technologies, DIAVAZ Mexico

Data and Analytics
Friday, September 15
11:00 am

For the first time in nearly 80 years, Mexico, with the energy reform, has opened up its oil industry to foreign investors, offering exploration and extraction blocks in Mexican territory to operate some fields according to new regulations established by National Hydrocarbon Commission (CNH). These reforms represent an historic opportunity to the private sector. This context is generating a new business model allowing the participation of new companies. DIAVAZ is an example of this new reality in the Mexican energy sector, implying strategic alliances and highly technical challenges to be solved in short periods of time to estimate potential areas for tender. DIAVAZ is an active company in the E&P sector that during last decade has been operating Ebano and Miquetla fields through operation service contracts with Pemex.

During the bidding rounds, the time to evaluate the data is limited and critical; companies have little staff, and stakeholders require fast and accurate investment recommendations. These conditions require high science and integrated solutions to be operated by skilled users.

Based on these needs and after an evaluation, DIAVAZ selected SIS technology (Petrel, Studio, Guru, and OFM) in order to address the challenging conditions that the energy reform imposes. In partnership with SIS, DIAVAZ planned and implemented a Petrel-Studio centralized and scalable environment having Guru as its multidisciplinary workflow guidance tool.

The Studio deployment represented a change of paradigm between the users as only critical data is saved in this new database concept, which does not require as much infrastructure as traditional ones. Complementary to this new concept of database, Guru represents an environment that reduces the learning curve and promotes productivity and knowledge capturing, ideal for experienced domain users with less software skills.

This implementation became a successful case study and represented the first Guru implementation in MCA. This project is being used as a reference to other companies participating in the bidding process to see the value of this collaborative, productive, and integrated work environment.

  • S. Dalessio (DIAVAZ Mexico)
11:00 am Subsurface Characterization (Room 1)

Petrel Structural Modeling and Gridding. Which grid to choose?” Overview of the workflow and the qualities and limitations of different gridding styles

  • M. Beardsell (Schlumberger)
11:00 am Subsurface Characterization (Room 2)

Optimizing the search for hydrocarbons in unconventional and conventional reservoirs through new-generation logging and data analytics

  • B. Sun (Chevron)

Optimizing the search for hydrocarbons in unconventional and conventional reservoirs through new-generation logging and data analytics

Subsurface Characterization (Room 2)
Friday, September 15
11:00 am

Automation is rapidly changing the face of the world. Driverless cars, smart buildings, robots, and drones – subjects of science fiction a few years ago – have now become a reality. Automating the interpretation of well-logging measurements through modern methods in big-data analytics holds great potential for reservoir characterization. Data-analytics based methods are adaptive, honor the information content of the data, and require little to no a-priori knowledge of the system under observation.

A novel data-analytics based methodology is developed by Schlumberger for automatic extraction of petrophysical information from new-generation nuclear magnetic resonance (NMR) logging measurements. From analysis of large quantities of logging data in a single or multiple wells, the methodology enables extraction of unique fingerprints of reservoir fluids. Additionally, the methodology provides longitudinal and lateral distribution of fluid volumes in the reservoir.

The new-generation logging tool was successfully utilized by Chevron for reservoir characterization in unconventional reservoirs in the Permian Basin and in conventional reservoirs in the deepwater Wilcox formation of Gulf of Mexico. Quantifying fluids, especially producible fluids, in unconventional reservoirs was critical for identifying sweet spots for drilling horizontal wells and for well-completion decisions. The fingerprints and volumes of fluids such as bitumen, light hydrocarbons, and water could be accurately predicted using the methodology, thereby aiding in reservoir management decisions. Application of the methodology in the deepwater Wilcox formation of Gulf of Mexico provided viscosity variation and insights about the producibility of the well.

  • B. Sun (Chevron)
11:00 am Eurasia

Full-cycle data integration: deployment of the Studio Environment in Tengizchevroil

  • M. Arystanov (Tengizchevroil)
11:30 am Well Construction

Kinetix Shale improves well performance in the Wolfcamp by 25% while reducing completion costs

  • S. Omarov (Manti Tarka Permian)
  • C. Douglas (Manti Tarka Permian)

Kinetix Shale improves well performance in the Wolfcamp by 25% while reducing completion costs

Well Construction
Friday, September 15
11:30 am

Like most shale reservoirs, understanding the production-driving mechanism in the Wolfcamp Formation in the Delaware basin is quite difficult due to several factors, including a large degree of variation in mineralogy, lithology, wetting characteristics, etc. Only after the production mechanisms have been determined, can an optimized completion strategy be developed that effectively maximizes the expected well deliverability performance.

This paper presents an operator’s approach to optimize future well performance by fully integrating all the data acquired in the Wolfcamp Shale. The Kinetix Shale workflow was utilized to determine the best lateral landing location in the reservoir and completion strategy. For the first time in the industry, the integrated completion workflow was coupled with the ShalePrime process that enabled the quantification of key parameters that are intrinsic to the fluid-rock interaction, as opposed to common industry standards that are purely empirical, with limited theoretical basis. This enabled the identification of the optimum flowback-aid additive, which ultimately reduced the overall completion costs.

This methodology was successfully applied on two separate horizontal wells in the Upper Woflcamp Shale Formation. The 60-day oil cumulative results showed an average increase of ~25% compared to their direct offsets, in addition to a reduction in the overall completion costs. Additionally, oil and chemical tracers acquired on the subject wells indicated that all of the treated stages were contributing to flow. The positive impact of these results has provided an excellent platform for efficiently determining the optimum well spacing in the Wolfcamp Shale and also serves as a model that can be applied to other unconventional basins.

  • S. Omarov (Manti Tarka Permian)
  • C. Douglas (Manti Tarka Permian)
11:30 am Unconventionals

Integration of log-based rock classification with core studies to delineate sweet spots in the Eagle Ford play, South Texas

  • D. Walker (EP Energy)
11:30 am Production Operations

A holistic approach to increase production for a Sonatrach satellite in Hassi Messaoud Field (on-going project)

  • L. F. Berkat (Sonatrach)

A holistic approach to increase production for a Sonatrach satellite in Hassi Messaoud Field (on-going project)

Production Operations
Friday, September 15
11:30 am

This project has a crucial importance as it is the first of its kind in Algeria and its success would lead to the same systematic approach for 16 more satellites in the Hassi Messaoud field, which is one of the biggest mature fields in the world. As this is an ongoing project, the outcome and final results will be included in the slides which will be presented at the forum in September.

Enhancing the production of complex networks in onshore, mature oil fields requires a holistic approach—looking at different components, from wells to the process side and from network debottlenecking to an improved production, back allocation, and surveillance. Based on this understanding, SH-PED requested Schlumberger to conduct a holistic approach studying W1C, one of Hassi Messaoud field’s largest satellites (more than 100 wells) with the objective of optimising and increasing its production.

To approach this challenge, five separate subprojects are defined to assess and study the individual uncertainties, starting at the inflow of the central processing plant and back-tracking to the individual wells. One of the main challenges is the interlinked nature of these subprojects and the fact that they are all part of debottlenecking the solution to enhance production and improve the accuracy of the production data, down to the individual contributors to the production.

The objectives of this study are to perform an assessment and study the individual field challenges, identify the root causes of the issues, and propose mitigation/improvement solutions.

  1. Inconsistency in the production metering at W1C-UTBS trunk line. SH-PED is experiencing inconsistencies in measuring the flow coming from W1C to the central processing plant. The flow measured discrepancy between measurements is in the range of 20%. Better consistency is required to ensure accurate flow measurements and back allocation.
  2. Incomplete separation at W1C satellite.
    It is common that increased gas in the production reduces the level of separation achieved. This can result in:
    • Carry through of oil droplet and condensates with the gas phase to the flare.
    • The oil phase contains gas and or water resulting in multiphase flow, affecting the metering and potential flow instabilities, with subsequent pressure drop.
  3. Production fluctuations upstream of W1C. Production fluctuations upstream of the W1C separator cause production loss due to an increased pressure drop and back pressure effects on the sub critical wells. These fluctuations would also make the separation process and the daily production forecast more challenging and influence the overall production.
  4. Uncertainty about the back allocated production rates. The back allocated production is based on estimated production rates into the central processing plant and not W1C satellite. With the uncertainty of the individual production contributions from each satellite into the central processing plant, the uncertainty of the back allocated values to each contributing well becomes a source of large uncertainty, creating ambiguity when used for history matching. An improved method to reduce the uncertainty of the back allocated values is under investigation, which will be based on the findings in the other subscopes in this project, in addition to input from data management and surveillance projects.
  5. Gas lift rate instabilities. Instabilities in the gas lift rate and pressure for each gas lifted well has been suspected by Sonatrach to influence production and limits the gas lift optimum to be achieved. Analysis of three wells by continuous monitoring of the wells, using the Gas Lift Well Surveillance pilot, is in progress to give insight about their gas lift fluctuations and their improvement potential. Based on the findings, the improvement potential for the gas lifted wells will be identified and actions related to the following improvement areas will be recommended.

  • L. F. Berkat (Sonatrach)
11:30 am Field Development Planning

Multi-scale reservoir simulations of polymer injection

  • D. G. Perez (YPF)

Multi-scale reservoir simulations of polymer injection

Field Development Planning
Friday, September 15
11:30 am

The purpose of this paper is to present a multi-scale reservoir modelling approach to assess economic viability for the development of a cEOR project in the current adverse oil price scenario. We present an on-going polymer injection project in a brown oil field in the western flank of the Golfo San Jorge Basin in southern Argentina as a case study for this methodology. The productive interval consists of a 1000- meters-thick low net-to-gross fluvial succession, in the Cretaceous Bajo Barreal Formation. The field produces a ~100 cP oil with very low recovery factor and a water cut of 94%, after 25 years of waterflood.

The need for high-resolution models is validated by a cell size sensitivity analysis on polymer injection simulations. We verified that almost 50% error on oil incremental forecasts by polymer injection is obtained if 50 × 50-m cells were used. Therefore, combining purpose-built dynamic models in different scales and economic evaluation we support the on-going execution of the EOR pilot project. Several static/dynamic models are built at different scales (from 10 km to 100 m) to capture depositional trends and model stratigraphic and sedimentary heterogeneities. We evaluate different physical aspects of the polymer injection process with specifically designed numerical simulations at appropriate resolution down to 1 x 1-m grid block. We conclude that detailed modelling and data acquisition are profitable decisions even in the current challenging economic scenario, aiming at reducing uncertainty and strengthening business cases. Indeed, laboratory and field measurements, identification of critical variables, and high-resolution modelling proved to reduce forecast uncertainty and strengthen business case economic indicators.

  • D. G. Perez (YPF)
11:30 am Business Transformation

Use of INTERSECT Simulator in Chevron

  • M. Kumar (Chevron)

Use of INTERSECT Simulator in Chevron

Business Transformation
Friday, September 15
11:30 am

The INTERSECT high-resolution reservoir simulator, which was developed jointly by Chevron and Schlumberger, enables black oil, compositional, and thermal simulation of highly heterogeneous or complex reservoirs. It incorporates unstructured gridding, which allows details around faults or fractures to be accurately modeled. Further, advanced field-management permits rapid evaluation of field-development strategies, and multi-segment well capabilities provide improved representation of horizontal wells and complex completions. This next-generation reservoir simulation software, which makes large field simulations requiring millions of grid blocks, was first commercially released in late 2009. Total joined the partnership in 2012.

In Chevron, the INTERSECT simulator has already been deployed on key projects worldwide, including all major capital projects. We started with strategic individual assets and are now doing enterprise-wide deployments. Our current INTERSECT simulation models include fractured reservoirs, water and gas injection, polymer injection, heavy oil/thermal recovery, and coupled reservoir and network modeling. Earlier INTERSECT models were created by either conversion of existing CHEARS™ model decks to the INTERSECT simulator, using a migrator software. Now, new models are being built using the INTERSECT simulator workflow model builder or the Petrel reservoir engineering module.

Early deployment of the INTERSECT simulator in Chevron started with the commercial release, and our plans are to deploy it to all of our assets by 2017. We have taken a structured approach to deployment, with a Project Manager and Change Management Team. The effort includes focused communication with business units on readiness and scheduling. The deployment encompasses integrated workflows. Further, we are building organizational capability through comprehensive training. 

Examples of recent developments and deployments, lessons learned, and best practices from deployments will be shared.

INTERSECT is a mark of Schlumberger; the INTERSECT simulator is a joint product collaboration of Schlumberger, Chevron, and Total.

CHEARS is a trademark of CHEVRON INTELLECTUAL PROPERTY LLC, and Chevron’s proprietary reservoir simulator.

  • M. Kumar (Chevron)
11:30 am Data and Analytics

Collaborative environment enhancement using Studio

  • M. Whitehall (Groupement Berkine)

Collaborative environment enhancement using Studio

Data and Analytics
Friday, September 15
11:30 am

Groupement Berkine is a joint-operating association formed in 1998 between SONATRACH (the national oil and gas company of Algeria) and Anadarko. Groupement Berkine is considered the biggest JV in Algeria in terms of oil production. This production rate comes from three mega projects located in the fields of Hassi Berkine South, Ourhoud, and, more importantly, El Merk field.

Groupement Berkine utilizes several G&G software solutions to perform its interpretations and evaluations. The corporate repository where all the raw data and interpretations are stored is based on the OpenWorks platform while the G&G interpretations are performed by the geologists and engineers using the Petrel platform. This diverse environment presents two main problems that were impacting the work efficiency and exchanges between the engineers:

  • Petrel users need access to the data of OpenWorks database
  • Petrel data generated by an end-user need to be managed and accessible to all other engineers

Groupement Berkine (GB) then expressed the need to organize the existing Petrel environment in such a way that the geoscientist population can have easy and fast access to data and then be able to share the qualified and validated data and models.

The Schlumberger solution suggested to address this issue was based on Studio technology. Studio is not only a project data management solution for Petrel, but also a new way of working, streamlining the asset team collaboration and the capture of project insight to take proper decisions. The implementation of Studio was then decided by GB and the project had as scope and objectives:

Provide a common and quality-proven data environment for geoscientists working in the Petrel platform (data from OpenWorks and reference Petrel project).

Provide real-time access for Petrel users within the Petrel interface to all data that are stored in OpenWorks with the ability to load data of interest.

Implement collaboration workflows between geoscientists working in different assets using Studio productivity tools, such as annotations, quality attributes, notifications, etc.

The project was then conducted conjointly by a team from both GB and Schlumberger and closed in a month timeframe. The new Studio environment has then offered to the client

  • Easy, fast, and secure access to different data types (interpreted well logs, interpreted horizons/faults) from several sources (Studio, OpenWorks, and Petrel projects)
  • Capitalize on expert interpretations done in Petrel and share them with subsurface teams
  • An efficient collaboration environment for static model workflows provided by Studio

  • M. Whitehall (Groupement Berkine)
11:30 am Subsurface Characterization (Room 1)

Deterministic simultaneous inversion for reservoir delineation and fluid/lithology characterization using Petrel’s QI Tools

  • A. Contreras (Woodside)

Deterministic simultaneous inversion for reservoir delineation and fluid/lithology characterization using Petrel’s QI Tools

Subsurface Characterization (Room 1)
Friday, September 15
11:30 am

Presented here is an assessment of the value of the Petrel QI tools for reservoir delineation and fluid/lithology characterization in a Triassic gas field.

The presentation will review the implementation of a three-step workflow comprising

  • An initial, log-based, inversion feasibility analysis
  • Deterministic, simultaneous seismic inversion, including low-frequency model building and inversion parameterisation
  • Quality checking and interpretation of inversion products.

For each step in the workflow, the presentation will address highlights, pitfalls, and limitations of the current QI toolbox implementation in Petrel.

In the test study, an initial feasibility analysis was performed to test the suitability of the seismic data quality and local rock properties for lithology and fluid discrimination via inversion. Cross-plot analysis showed that a fluid-sensitive modulus attribute can be effectively used to discriminate between brine and gas-bearing sands, with gas sands showing the lowest attribute values. Fluid substitution and synthetic image gather modelling shows a clear increase in amplitude when brine is substituted with gas. Additionally, comparison of the partial angle stacks at the gas discovery well location shows a clear increase in amplitude with angle.

The seismic inversion phase consisted of (1) trace-alignment (seismic trace alignment module), (2) well-tie (seismic well-tie module), (3) deterministic, angle-dependent wavelet estimation (wavelet extraction module), (4) low-frequency modelling (inversion property builder), (5) inversion (simultaneous inversion module), and (6) QC of the results. Deterministic, simultaneous inversion was conducted by integrating the four partial angle stacks, the angle-dependent wavelets, and the low-frequency models using the Petrel inversion algorithm for P-impedance, Vp/Vs, and density. The results were then quality-checked in the data space by inspection of the residuals between the inverted synthetic and input reflectivity data and the relative misfit and in the model space, plotting the measured logs vs the inversion results extracted at the well location. Finally, a fluid-lithology sensitive volume was computed from the inverted volumes, and a great correlation was achieved between the derived fluid attribute results and the gas-bearing sands.

The final phase of visualization and interpretation of the results consisted of attribute extraction, stratal slicing, and geobody extractions. These techniques were all effectively used to discriminate between sands and shales and delineate the gas-bearing sands with the lowest fluid attribute values. Although most of the Petrel QI tools were successfully implemented in this reservoir characterization study, some opportunities for improvement were identified, including simpler functionalities for inversion parameters testing, inversion results QC, and stratal slicing.

  • A. Contreras (Woodside)
11:30 am Subsurface Characterization (Room 2)

A geoengineering TASK long-march to a great success: Development of a unique and giant gas field in Kucha Foreland Basin

  • Q. Wang (PetroChina)

A geoengineering TASK long-march to a great success: Development of a unique and giant gas field in Kucha Foreland Basin

Subsurface Characterization (Room 2)
Friday, September 15
11:30 am

The Cretaceous Bashiqike sandstone formation in Kucha Foreland basin contains huge gas resources. The targeted interval is super deep (>6500 m up to 8500 m TVD), ultra-tight (matrix permeability <0.01 md), HP/HT (120+ MPa, 150+ degC), and naturally fractured. It is beneath very thick hybrid salt layers (up to 2000 m) with interbedded gypsum and high-pressure, water-bearing, and unstable shales. The combination of pre-salt, super depth, and steep overthrust features, makes surface seismic characterization face incredible challenges in structure description and “mission-impossible” natural fracture characterization. Above the salt is a thick (up to 3000 m) and high-angled conglomerate formation. Besides, the gas field is located in the remote Gobi desert with harsh natural environment and geographical conditions. All of such meeting together, make this gas field be unique worldwide and present challenges of extremes from both the geoscience and engineering points of view.

PetroChina Tarim and Schlumberger established a joint geoengineering team with careful planning to persistently attack the challenges using this world-class championship team – called the Tarim and Schlumberger Kucha (TASK)—since 2012. It includes four major steps that focuses on 1) understanding reservoir, 2) seeking production breakthrough, 3) optimizing stimulation strategy, and 4) optimizing well and field performance while continuing progress of exploration and development. With an integrated software platform and cooperative work environment, the TASK team has established a comprehensive technical approach and workflows with continuous innovation to ensure seamless integration from geosciences to engineering applications, between technical research and operational execution. The technical efforts involves specifically designed lab tests including big-core tests, thorough petrophysical evaluation and natural fracture characterization, 3D structural geology modeling, 1D to 3D reservoir geomechanics modeling, unconventional hydraulic fracture modeling, high-resolution reservoir simulation, data mining, and customized design or upgrades of engineering technologies such as a slim-hole HP/HT perforation system.

  • Q. Wang (PetroChina)
11:30 am Eurasia

Evaluation of uncertainty profiles gas and condensate production and optimization of the project decisions

  • S. Redikultsev (Rospan)
12:00 pm Well Construction

New approach to optimize severe wellbore instabilities and losses while drilling in the North-East of Algeria

  • N. Haddoum (Sonatrach)

New approach to optimize severe wellbore instabilities and losses while drilling in the North-East of Algeria

Well Construction
Friday, September 15
12:00 pm

Sonatrach have faced multiple problems in terms of wellbore instabilities and losses while drilling a number of wells in the north region of Algeria (SE Constantine basin). These problems have negatively influenced drilling efficiency and consecutively reservoir evaluation. In collaboration with Schlumberger, an integrated project has been developed in order to perform a drilling integrity analysis of existing wells having the most complete and meaningful set of data. The objectives of this project are:

  1. To analyse the root causes and provide geomechanical solutions for drilling integrity analysis
  2. To apply these solutions to the actual problems encountered in the northeastern region of Algeria
  3. To implement a work-plan enabling the creation of geomechanical models, to map observed drilling issues (DrillMAP), and to provide preliminary indications and recommendations supporting upcoming drilling operations

After an audit of the data provided by Sonatrach including a preliminary analysis of the drilling events, a (1D) post-drill geomechanical modelling of 11 selected wells have been conducted in order to identify the root causes of observed drilling issues. In order to integrate all available information and provide more comprehensive geomechanical information, 3D geomechanics modelling at reservoir scale has also been performed using Petrel-RG and VISAGETM. Then, using MWP, a Petrel plug-in, a pre-drill geomechanical characterisation, namely mud weight window (MWW) and DrillMAP, have been constructed to support well design and planning of the new well A. Moving from the post-drill analysis and the planning of well A drilling, the next step was dedicated to the real time monitoring. During this phase, the pre-drill geomechanical model of well A was constantly checked and, if required, corrected on a daily basis using LWD data. Based on that, updated recommendations have been sent to the drilling team by means of DrillCAST reports. During and after drilling well A, it was noticed that the well was drilled in a good condition, saving Sonatrach 16 days of drilling. After logging operations, it was noticed that the well was in gauge. These results confirm the added value of geomechanics (post mortem analysis or real time) to solve the problem of well instability and integrity in O&G field domain. After the success of this project, the same approach will be conducted in other areas in Algeria, like Berkine basin.

  • N. Haddoum (Sonatrach)
12:00 pm Unconventionals

The strategy breakthrough and key reservoir stimulation technology to the lacustrine tight oil reservoir exploration and development in Ordos basin China

  • G. Liu (PetroChina)

The strategy breakthrough and key reservoir stimulation technology to the lacustrine tight oil reservoir exploration and development in Ordos basin China

Unconventionals
Friday, September 15
12:00 pm

The Triassic Yanchang Formation is currently a hot spot for lacustrine tight oil exploration in the Ordos Basin, China. As a first proven big oil field in Xin Anbian area, Ordos Basin, the proved reserves of Xin Anbian oilfield tight oil are over hundred million tons, which is the Petrochina strategy breakthrough for oil & gas discovery. The potential tight oil reservoir is primarily distributed in the Chang 7 member of Yangchang formation, which features highly heterogeneous and uneven petrophysical properties across the basin. The Chang7 member tight oil reservoir is characterized by complex lithology with various mineral composition (quartz, carbonates, feldspars, pyrites and volcanic ash), low porosity, and complicated pore structure. It is challenging to identify the reservoir and discover the pay zone with conventional measurements. Therefore, special logging technologies and core testing methods are necessary for reservoir identification and evaluation.

To meet the Ordos basin lacustrine tight oil reservoir E&P challenges, PetroChina and Schlumberger CHG SIS pioneered a project to determine optimal technologies and workflow to fully characterize reservoir quality (RQ), source rock quality (SQ), and completion quality (CQ) with the use of Techlog and Petrel software by integrating the advanced wireline scanner family measurements and core testing. The major goal of this study is to identify the “sweet spot” by characterizing the reservoir quality, source rock quality, and geomechanics quality of Chang 7 member of Yangchang formation vertically and laterally across the basin.

Calibrated with the advanced logging measurements and core data from 28 key wells, 84 wells with basic logs were evaluated to develop the approach and 3 “quality evaluation model for the lacustrine tight formation. The final deliverables of this pioneer project are used as guide to optimize the field E&P strategy in the basin for the best tight-oil sweet spot selection, especially the key technology breakthrough on multistage horizontal well geoengineering stimulation design. The wells test well based on the recommendation from this study got promising production after fracturing.

  • G. Liu (PetroChina)
12:00 pm Production Operations

Kuwait Integrated Digital Fields (KwIDF) for North Kuwait Jurassic gas: The future of integrated asset operations

  • S. Al-Qahtani (Kuwait Oil Company)

Kuwait Integrated Digital Fields (KwIDF) for North Kuwait Jurassic gas: The future of integrated asset operations

Production Operations
Friday, September 15
12:00 pm

In 2010, KOC pioneered its digital journey branded as Kuwait integrated digital fields (KwIDF). The North Kuwait Jurassic Gas KwIDF is a success example of value realization from DOF concepts being applied to a green field since its inception. The complex fractured, heterogeneous carbonate reservoirs, critical reservoir fluids, high H2S and CO2 concentration, HPHT wells, and hostile environment poses a considerable production challenge in the North Kuwait Jurassic Gas fields. A robust smart field technology was deployed and being upgraded in phases to address the Jurassic challenges in the best possible way.

With the ultimate aim of asset optimization, the KwIDF system, currently encompassing 44 wells, has so far addressed critical HSE events and effectively integrated real-time data with online scientific workflows to help realize 3% production gains year on year. The petroleum engineering workflows make it possible for engineers to effectively stabilize, ramp up and optimize production such that reservoir management strategies are followed.

The North Kuwait Jurassic Gas KwIDF system has proven to be a key tool to support the 1-BCFPD gas production target by 2022. North Kuwait Jurassic fields have a major milestone in 2017, whereby the asset target is to ramp up the production, from the current level of 210 MMscfd to 500 MMscfd gas, by augmenting 70+ wells and 3 new, early-production facilities. KwIDF is expected to play a critical role in this expansion, with a strategy to enhance the workflows by integrating process facilities data, such that operational philosophy of these facilities is aligned with the asset production strategy.

In this session, we will discuss how a combination of real-time infrastructure and data, well automation, and petroleum engineering workflows combined with collaborative work practices have provided good visibility in unlocking the true potential from the Jurassic gas fields. We will also elaborate on recent KwIDF workflows, for virtual metering supported by additional field measurements; and blended API workflow, to track the crude API density at the facility outlet; and demonstrate how H2S and CO2 rate calculation workflows, along with the choke sensitivity, helps to optimize gas production based on H2S and CO2 specifications. With the field expansion, the technology upgrade is also planned to improve well performance monitoring, virtual flow metering (VFM), surface to subsurface integration, choke management, hydrate control, and well and pipeline integrity.

  • S. Al-Qahtani (Kuwait Oil Company)
12:00 pm Field Development Planning

Reservoir modeling guidelines and best practices: A significant step on improving subsurface modeling and field development plan

  • F. Al-Jenaibi (ADNOC)

Reservoir modeling guidelines and best practices: A significant step on improving subsurface modeling and field development plan

Field Development Planning
Friday, September 15
12:00 pm

The mission of a national oil company is to guide the operators towards value realization, in a fashion compatible with the management of the nation’s hydrocarbon resources over the short, medium, and long term. The field development planning (FDP), a critical step in asset value realization, is nowadays based on advanced numerical simulations.

As a result, ADNOC is invariably brought in to comment on the validity, suitability, and adequacy of the numerical simulation prepared by the various operators.

The time required to verify the model and the level of effort involved is significant and increasing.

To manage this challenge, ADNOC decided to develop guidelines:

  • To consistently ensure best quality of the produced models and FDPs
  • To structure and prepare the operator’s request for endorsement of the FDP
  • To ensure consistency across operators and JV
  • To accelerate model approvals with standard plots and maps

This will solidify the processes for subsurface assessment, simplify field development plan review, and streamline the field development planning (FDP).

The deliverable of this project by the Schlumberger SIS consulting team in Abu Dhabi is a guideline that includes structure of the processes used for the systematic review of static and dynamic numerical models and the simulation results thereof.

This project is the first of its kind within ADNOC at this level of technical analysis and domain integration and opens the door for standardization in subsurface characterization.

  • F. Al-Jenaibi (ADNOC)
12:00 pm Business Transformation

High performance cluster simulation environment

  • C. Moller (Maersk Oil)

High performance cluster simulation environment

Business Transformation
Friday, September 15
12:00 pm

Maersk Oil was faced with a technology and cost dilemma – how to best replace their small simulation clusters in Copenhagen, Aberdeen, Doha, Aktau, and Stavanger for reservoir simulation runs that were utilising old hardware, expensive to maintain. In addition, reservoir engineers at all sites were demanding the capability to run larger, more complex reservoir simulations, with increased frequency, and faster turnaround in a market where lower oil prices are dictating business decisions. Would it be best to replace all the clusters at individual sites or purchase one large high performance cluster environment (HPCE / private cloud) that could be shared globally throughout the Maersk Oil organisation?

Maersk Oil, headquartered in Copenhagen was challenged to provide the best solution that aligned with the corporate business objectives to reduce the total cost of ownership. A phased approach was adopted due to the high complexity and cost:

  • Phase-I – implement new HPCE in Maersk Oil, Copenhagen, for Copenhagen use only (2015). 
  • Phase-II – test the global environment with Maersk users in Doha, Aktau, Aberdeen, and Stavanger (2015).

With the initial success of Phases-I and II, a further four phases have since been approved: 

  • Phase-III – construct an INTERSECT centre of excellence (2016) 
  • Phase-IV – globalise all the reservoir simulation software licenses (2016) 
  • Phase-V – increase capacity to host all simulation activities (wave simulation, computational flow dynamics) (2017) 
  • Phase-VI – globalise the reservoir simulation data (2017) 

The overall target deliverables are as follows: 

  • Optimal performance for the ECLIPSE, INTERSECT, PetroMod, and VISAGE simulators 
  • Seamless integration with the Petrel exploration & production software platform for job submission and simulation results viewing 
  • Efficient management and maintenance of the HPCE environment
  • An overall total cost of ownership reduction 

It was decided to implement a turnkey solution from Schlumberger Integrated Solutions in Copenhagen, Denmark, for the installation, configuration, and implementation that included proactive and ongoing maintenance.

The Phase-I solution provides 104 nodes with 2120 cores, delivering one of the largest SIS private cloud environments. In addition, onsite proactive maintenance is provided every month in parallel to the Schlumberger 24/7 Customer Care Center support system.

Phase-I was a great success with seamless operation and ongoing proactive maintenance focused Schlumberger support and training. The configuration of the centralized private cloud environment together with the expert domain knowledge have enabled the business units to extract the maximum value of fully integrated workflows across full field models, optimizing project cycle time between stage gates.

  • C. Moller (Maersk Oil)
12:00 pm Data and Analytics

Integrated Asset Modeling for mature oil fields using cloud technology

  • J. Louis (Woodside)

Integrated Asset Modeling for mature oil fields using cloud technology

Data and Analytics
Friday, September 15
12:00 pm

A mature oil field, located offshore Exmouth in Western Australia, has been under production for about 10 years, operated by Woodside Energy Ltd. The oil from the field is being produced via long and complex multilateral wells in a thin oil rim. The subsea wells are tied back to a floating production storage and offloading (FPSO) vessel via two production manifolds. Produced water is disposed by water injection, and produced gas is reinjected into the field’s gas cap.

In dynamic modelling of this field, high-resolution simulation is required to preserve field heterogeneities, to allow representative modelling of water coning and gas cusping, to model the large
number of multilateral wells, and to accurately identify undrained targets for further infill development. ECLIPSE has been the traditional reservoir simulator employed in modelling this oil field, but it has its limitations, in particular with the model scale and run times.

A project was initiated to investigate the use of INTERSECT, a relatively new reservoir simulator, which was used on this oil field to run large-scale models with millions of cells within a reasonable time frame. The project also included the implementation of a complex gathering network model, along with associated field management logic and to take into account the pressure losses occurring in the network and to optimize production from the field. This was achieved by coupling the reservoir simulator with a production network simulator, incorporating an updated version of the reservoir-to-network coupling.

Another important element of this project was the successful proof-of-concept of the use of “cloud computing” to submit and receive jobs from servers located in a location remote to the user. This opens up a potential avenue for running multiple simulations in the Cloud at higher speeds without having to build or significantly upgrade the onsite high-performance computing infrastructure. This project successfully demonstrated the conversion of an ECLIPSE simulation data deck to an INTERSECT simulation deck native to Petrel Reservoir Engineering. It also demonstrated the use of the Field Management GUI process for coupling with a network solver from the Petrel platform and with limited customized scripting. Benchmarking simulation runs demonstrated that the resulting simplified, coupled-network model successfully reproduced the results of the equivalent ECLIPSE network simulation.
INTERSECT dynamic results were validated against ECLIPSE field and well results with and without the network setup. Benchmarking of these models was then carried out on the Cloud from Petrel, which shows that this oil field can be simulated successfully and faster using INTERSECT rather than ECLIPSE.

This project has paved the way for INTERSECT to be considered for other assets in Woodside, with appropriate functionality testing recommended as a precursor to full implementation.

  • J. Louis (Woodside)
12:00 pm Business Transformation

Petrel GURU in DONG Energy Oil & Gas: Implementation, usage and governance

  • K. Nordstrom (DONG Energy)

Petrel GURU in DONG Energy Oil & Gas: Implementation, usage and governance

Business Transformation
Friday, September 15
12:00 pm

DONG Energy O&G is a middle-sized Danish-based company with a footprint area offshore North West Europe and with G&G personnel in Copenhagen, Stavanger, and London.

DONG Energy O&G has for many years used Petrel as the main subsurface platform for interpretation, modeling, uncertainty analysis, etc. We have, over that period, developed a strong data management culture with well-defined governance structures around our master data repositories, Petrel projects, and data.

However, we have realized that one of our challenges is to ensure that our best practises, uniform processes, and defined workflows are secured, made accessible, and used across the organisation (both between assets and geographically), and that we need a ‘container’ for capturing this information. We have over the years introduced various solutions (workspaces, homepages, closed forums, etc.), but too many information sites led to the problem that gained knowledge was difficult to find, which, in the end, led to nonproductive time. The goal has been to secure the knowledge in one centralized location that was easily accessible and would generate direct value for the users. Schlumberger introduced Petrel GURU, which is a step in the right direction to solve our challenges.

Petrel GURU is a workflow-centric guidance module containing more than 1300 predefined pages of content, such as quick video guides, guided workflows, theory pages, training sequences, quality checks, etc., covering Petrel processes in all domains. Additionally, GURU’s embedded editor provides us with the possibility to capture our own knowledge and processes, present them in a uniform context, and hence give the Petrel users the possibility to access this information and help as an integrated part of their daily Petrel work. Information presented in GURU has to be precise and trustworthy and hence requires strong quality control and quality assurance processes before it can be released to the users.

This presentation will give insight to the thoughts and ideas we have had around the implementation of GURU in DONG Energy O&G with special focus on our own customized content and the governance processes we are implementing.

Note. Co-author: Mette Juncker Brædstrup, Geoscientist, Schlumberger

  • K. Nordstrom (DONG Energy)
12:00 pm Subsurface Characterization (Room 2)

A cross disciplinary approach to hydrocarbon containment in the Wisting area, Barents Sea

  • J. R. Granli (OMV Norge)

A cross disciplinary approach to hydrocarbon containment in the Wisting area, Barents Sea

Subsurface Characterization (Room 2)
Friday, September 15
12:00 pm

Maturation of subsurface understanding always requires a cross-disciplinary effort. A continuously higher degree of specialization for the individual disciplines usually requires a team effort, especially in complex geological settings. Wisting and surrounding areas, in the Barents Sea is considered a complex setting. It is Influenced by extensive tectonic activity from Cenozoic to Neogene where several episodes of uplift and erosion have resulted in a highly faulted region called the Hoop Fault Complex. Wisting is at the crestal position of this complex with light oil in excellent Realgrunnen reservoir.

In these geological circumstances, described hydrocarbon containment is considered a key risk. Both the Wisting main compartment and also the first appraisal Hanssen compartment are (fortunately) contained, but we know that not all fault compartments work, even when they have support from convincing seismic DHIs direct hydrocarbon indicators. The second appraisal, Bjaaland compartment, came out as a failure with blown seal and residual saturation, in spite of a convincing seismic DHI.

After Bjaaland, a new methodology for assessing hydrocarbon (HC) containment were tested and calibrated. This methodology is enabling analysis of potential leakage routes for hydrocarbons from the reservoir into the overburden under different perturbations of the tectonic stress regime.

Input to this new methodology is typically geological features extracted from 3D seismic data like fault-network, chimneys, porous facies, and pockmarks. Seismic DHIs and CSEM indicators are used as clues for the presence of hydrocarbons. Extraction of the geological features from 3D seismic uses e.g. Seismic DNA to characterize DHIs and fault networks. Stress perturbations on the fault network are performed to analyze opening and closing parts of the fault network.

Frequent and very active cross-disciplinary interaction was a key success factor during our project execution and we managed to enter “almost” a one-team spirit across company barriers. Key motivation factors, such as learning and vitality, were vital for generating interesting results and valuable information that would be difficult to achieve in regular project outsourcing.

In retrospect, our overall project scope on fluid containment was great, but duration was probably too limited to fully connect and achieve even better results and higher value from the collaboration.

The presentation will elaborate on technology, the results achieved, and their impact on Wisting. It will also reflect on how important geoscience integration is, how much everyone agrees to its importance, and still how unusual it is seen to its full potential. The latter part will be spiced with some real experiences of what it takes.

  • J. R. Granli (OMV Norge)
12:00 pm Eurasia

Simulation of Southeastern Dragon Field by model creation using full tensor permeability

  • G. Sansiyev (VNIINEFT)