bluuebunny/crossref_metadata_2025 huggingface dataset:
The BP FIELD OF THE FUTURE Programme: The Continuing Mission To Deliver Value
Authors: Dickens Jeff , Latin David , Verra Graeme , Blosser William , Edmonds Greg , Grimshaw Greg
Published: July 2010

BP's digital oilfield initiative, the Field of the Future Technology Flagship, has been developing and deploying distinctive operational capabilities since it's inception in 2005. This paper describes the growing track record of value delivery, achieved through pace and scale deployment. These capabilities, which continue to be developed, support a relentless drive for continuous improvement in our asset operations, aiming at delivery of significant production (100mboed BPnet) and reserve (1bnbbl) targets by 2017. We report significant progress toward meeting these targets and highlight new key lessons from our growing body of experience.

The Field of the Future concept is now a routine part of how BP builds projects and operates fields across much of our portfolio. It impacts a significant and growing proportion of net production and routinely supports >80% of our top 100 wells. A range of monitoring, analytical, optimization and collaborative solutions are applied according to asset needs and value opportunities.

The in-house solutions have delivered over a third of the production target so far - ahead of plan. When integrated with general bought-in solutions, base infrastructure and collaboration benefits, we are routinely adding more than 50mboed gross production per annum.

The Paper presents examples of the variety of capability, technology and solution applications that have underpinned this continuing successful value delivery.

Key to this success has been: Establishing an effective, balanced approach to R&D, deployment and value realization;Developing clear linkage to business needs and functional priorities as a basis for effectively engaging the customer.

Areas of continuing challenge include: Sustaining uptake and usage when faced with issues and barriers arising from technical, business and organizational diversity in the asset portfolio;Competing or aligning with other business priorities and initiatives, especially in a cost challenged environment.

Looking forward, the common challenge all operators face is firmly on making it an industry-wide reality, and to fully embed "intelligent energy" in all that we build and operate.
Model Based Operational Support - Adding Assurance to Operational Decision Making
Authors: Stenhouse Bryn , Woodman Malcolm , Griffiths Peter
Published: July 2010

Managing and optimising BP's integrated operations presents an increasingly complex challenge with the move to deeper- water production and the use of sub-sea processing and multiphase tiebacks from satellite fields. Production system optimisation requires the simultaneous assessment of flow stability and well draw-down maximisation whilst honouring the constraints of reserves recovery though the reservoir management depletion strategy.

BP has a strong track record of applying fundamental mechanistic models to support operational decision making and optimisation. When reconciled with real-time and historical production data, physical models of a production system increase operators understanding of the system and allow changes to operating strategy to be made with increased confidence. Moreover, inferred model parameters can be use to track the health and efficiency of component parts of the system feeding an enhanced predictive maintenance capability.

Mechanistic models of a production system are themselves complex and challenging to use and maintain. Normally their use is restricted to modelling experts primarily for design purposes or to support troubleshooting following a production upset condition. Delivering such models for use within an operational environment requires a large number of issues to be addressed, in particular how such models can be applied quickly and robustly with assurance, and how they are scoped and maintained.

This paper outlines how BP E&P is tackling these issues through the Field of the FutureTM Model Based Operational Support programme as the capability is deployed further within the Upstream organisation.
Enough is Enough: Data Sufficiency
Authors: Bailey Richard , Ziegel Eric , Sprague Kip , Hedges Bill
Published: July 2010

BP can now target its corrosion inspection program on pipelines where there is a statistically validated shortage of data. Resources can be shifted from lines where the same statistical approach indicates that adequate quantities of data have already been acquired. This exciting capability has been realised and trialed by the FieldoftheFuture flagship technology team and builds on its successful track record of working with large quantities of data from real time applications. What has been demonstrated is that BP's experience with real time process data is equally applicable to very large databases of historical inspection data. Strategies can be developed that respond to the most recent inspection results as these are acquired.
A Step Forward in Collaborative Well Planning: Deployment Challenges Under Windows Platform for Drilling Application in the Ekofisk Operations
Authors: Lahlah Nour-Eddine , Herbert Mike , Bashford Karen
Published: July 2010

The implementation of a 3-D visualization platform for drilling application within the Onshore Drilling Center in Tananger was among one of the targets in the new plan for enhancing the drilling efficiency and evaluating NPT. The most challenging step was to deploy collaborative well-planning software under a Windows platform in addition to the interaction between the Norway database and the drilling application.

The implementation process of the visualization platform was carried out by deploying Windows machines in different locations. The challenge faced was the connectivity between the global database and the drilling platform. This implementation follows the Integrated Operation vision, which is enabled by connectivity, collaborative technologies, and multi-discipline workflows.

Historically, this visualization platform under Linux has been used by the GGRE (Sub Surface and Reservoir Evaluation) engineers, but not deployed through the drilling community. This paper discusses the new synergy of enhancing the collaborative work in logical steps. The first step is to provide the appropriate hardware and software for the integrated operation, and the second step is to accommodate the new tools within the ODC workflows.

Another way of working is starting to take place through bringing GGRE and drilling staff engineers together. This collaborative well planning requires the coordination of different operating platforms, databases, disciplines, and hardware to ensure effective well planning. Specific operational preparedness and coordination are needed prior to the well session.

The live well planning sessions illustrate how the reservoir team, overburden team, and drillers can all work together on the plan simultaneously through importing or exporting targets from the drilling database. Different platforms can be used during the well planning session to allow for free access to G&G data, third-party data, and well planning data through the use of a visualization drilling engine.

The case history provided in this paper discusses how real-time visualization was used to monitor drilling trajectory with a geological model.
A New Approach to Knowledge Capture: Center of Excellence for Sand Control Completions as a Model
Authors: O'Neill Dennis M. , Walls Lauren R. , Sickle Ed Van , Baker Brad
Published: July 2010

In large global organizations, experts who collaborate with their colleagues in the Digital Oilfield of the Future (DOFF) are geographically dispersed and mobile. Their time is precious and they cannot readily be distracted from their primary functions to participate in traditional knowledge-capture activities. Therefore, it is extremely desirable to automatically identify these experts, capture and codify their knowledge, and provide access to them from anywhere in the world at the time their knowledge is needed. This paper describes a new approach to this challenge.

We investigated a number of approaches including a prototype system to automatically identify communities of interest, capture and index the electronic documents relevant to the community of interest, and populate a globally accessible "knowledge space." This knowledge space provides a mechanism to access the relevant experts in real time using location-/presence-aware collaboration tools.

We evaluated this method in the context of establishing a Center of Excellence for Sand Control Completions. In establishing this Center, we began using conventional techniques. This initiative, however, was also viewed more strategically – as a vehicle for establishing "a new way of doing business," and it also served as a platform for testing approaches that would allow us to rapidly deploy the solution to other domains.

This exercise demonstrated that significant improvements can be made in collecting, organizing and disseminating actionable knowledge from a dispersed community of technical experts. It also provides a real-time mechanism for leveraging the implicit knowledge of these experts in a globally mobile workforce. This has significant relevance in the DOFF arena as it enables an organization to "know what it knows" with less effort than traditional knowledge management and collaboration tools.
Well and Reservoir Management Project at Salym Petroleum Development
Authors: Mabian Andrew , Volokitin Yakov , Beliakova Natalia , Genkin Jean-Mark , Hagelaars Ad , Pickles Mike , Diamond Joe
Published: July 2010

Salym Petroleum Development (SPD) has embarked on an ambitious Oil Field Management Improvement Program with as key objectives to: Optimise Production (2.5% additional production through reduction of Locked-in-Potential and better reservoir pressure maintenance; unscheduled deferment less than 1% through reduction of ESP trips).Increase Ultimate Recovery (Increase RF by 1%; platform for future EOR project; robust basis for infill drilling).Reduce OPEX (increase ESP mean time between failure; contain chemical consumption costs; in field staff journies reduced by 10% /annum; less than 3 non-critical loss of integrity incidents per year).

The goal of this paper is to present SPD's approach to Oil Field Management in the context of a West-Siberian water flood. Oil Field Management is based on the Value Loop (Figure.1) where data is acquired from physical assets (reservoir, wells, facilities) and subsequently incorporated into models that drive the optimization of these same physical assets. The value loop has different cycling times ranging from seconds to decades (Figure.2). Traditionally, the shortest value loop is called Real Time Optimization ("RTO") with a time span measured in seconds, minutes and hours, followed by Well and Reservoir Management ("WRM") with a time span measured in weeks, months or years, and finally Hydrocarbon Development Planning ("HDP") with a time span measured in years, if not decades. Figure.1Value LoopFigure.2Cycling Time
Energy and Environment: The Ultimate Test of E&P "Intelligence"
Authors: Kapteijn Pieter
Published: July 2010

In the next few decades the E&P Industry will face a unique confluence of two major challenges: it must continue to provide the world with sufficient oil and gas to support global development, while at the same time help it reduce the environmental impact of fossil fuel use, with a focus on the reduction of green-house gas CO2 emissions. This calls for innovative technical solutions and new approaches to the design and management of increasingly interdependent energy- and CO2 value chains.

The "intelligent" capabilities that the industry has developed over the past decade can be leveraged to meet these twin challenges. The combination of CO2 EOR with Carbon Capture and Sequestration (CCS) in particular, offers attractive opportunities to combine enhanced oil- and gas recovery with GHG reduction, in a profitable way. This can be done at the level of individual field developments but also at the level of integrated energy/CO2 systems.

The technical and economic implications of an "eco-efficient" approach to the design of CO2 EOR projects are discussed, taking a North-Sea EOR feasibility study and CO2 supply project example. These types of projects greatly benefit from "oilfield intelligence" to improve ultimate recovery and optimize CO2 capture, use and storage.

It is concluded that eco-efficient and intelligent technical and commercial design will have to become a core capability of the E&P Industry.
Single-Well In-Situ Measurement of Residual Oil Saturation after an EOR Chemical Flood
Authors: Arora Shyam , Horstmann Dirk , Cherukupalli Pradeep , Edwards John , Ramamoorthy Raghu , McDonald Tom , Bradley David , Ayan Cosan , Zaggas John , Cig Koksal
Published: July 2010

The MicroPilot* is a log-inject-log technique providing a single-well in-situ measurement of enhanced oil recovery flood geometry and changed residual oil saturation. The fluid to be injected is transported downhole in a sample chamber and injected into the formation through a pencil sized hole. Borehole electric images and high resolution saturation logs are recorded before and after fluid injection. The logs show the change of residual oil saturation. The dimensions of the swept zone and surrounding oil bank are visible on the borehole image. These dimensions and saturations can be used to history match the reservoir simulation of the EOR process.
Thermal Developments in Petroleum Development Oman's Southern Fields - An Update
Authors: Thum M. , Leith E. S. , Van Wunnik J. N. , Mandhari M. S. , Clark H. P.
Published: July 2010

A programme of thermal developments is being rapidly matured in Petroleum Development Oman's (PDO) Southern Oil Directorate. This targets several billion barrels of heavy oil deposits in clastic reservoirs at depths between 800m and 1800m. Cyclic steam stimulation and steam drive applications dominate the current development program. High-pressure steam injection and air injection applications are also pursued in some fields through studies and laboratory experiments.

Steam trials in three heavy oil fields spearhead the thermal developments and results are presented. These steam trials provide further insights to optimise the ongoing full field developments. The paper also describes a portfolio management approach to thermal developments, given that many of the target fields are in close proximity and can share the same infrastructure and development methodologies.

One of the main heavy oil full field developments has been matured from a Feasibility stage to Final Investment Decision in just three years. In this particular case, unique opportunities and challenges for thermal development arise due to the depth and thickness (200m) of the heavy oil column, with an underlying large regional aquifer. Specific topics addressed include thermal well cost reductions, urban planning, minimising additional gas requirements through COGEN, water management, development of a new Operating Model for Lean Steam Well & Reservoir Management and Operations, and overall integrated project management.
SAGOGD Feasibility in a Sparsely Fractured Carbonate Reservoir with a Thin Oil Column
Authors: Said Dhiya MM , Van Wunnik Johannes M
Published: July 2010

The field under study is a fractured carbonate of low matrix permeability (∼15mD) and modest fracture permeability (<1200mD). The structure is relatively flat with a maximum movable oil column of 60m and a median thickness of 30m and is underlain by a strong aquifer. The live oil viscosity is 7cp. To date the field has recovered a small fraction of its STOIIP, mostly under natural depletion and WOGD. The field is scheduled for re-development by Cold Gas-Oil Gravity Drainage (CGOGD). The feasibility of a later phase of development by Steam-Assisted GOGD (SAGOGD) was evaluated and is the subject of this paper.

The field's reservoir properties present a unique set of challenges for an SAGOGD development. Firstly, the relatively low oil viscosity at initial conditions is unfavourable for a large viscosity reduction by heating. Also, the extent of the structure together with the modest fracture permeabilities complicates the spread-out of steam over the field. Finally, heat transfer efficiency to the matrix is problematic given the small thickness of the reservoir and the large matrix blocks.

The SAGOGD development strategy calls for simultaneous gas and steam injection by injectors that are spread out over the field, which stabilises the oil rim, spreads out the steam and reduces aquifer water influx. The incremental recovery over CGOGD was demonstrated to be substantial (16% of STOIIP) with an acceptable oil-steam ratio. Analysis of physical processes contributing towards recovery showed that viscosity reduction was still the main contributor to oil recovery.

Significant uncertainties remain to be reduced before committing to an SAGOGD development. Besides the wide range of uncertainty in incremental recovery (+/-60% from the base case), water supply and disposal requirements are major challenges for the steam project. Whilst these latter are being evaluated, the initial phase of CGOGD will narrow subsurface uncertainties for SAGOGD development substantially. In this paper the subsurface elements of the study will be discussed.
Steam Flooding a Thick Heavy Oil Reservoir: Development of Numerical Tools for Reservoir Management
Authors: Al-Hinai Suleiman M. , van Wunnik John , Al-Shureqi Hamed
Published: July 2010

In a number of fields in Oman thermal developments are being implemented. One of these fields is located in South Oman and contains an exceptional 200 m thick oil thick column of medium to heavy oil (200 to 800 cp). This sandstone reservoir is at a depth of 1050 m below surface and is underlain by a modestly strong aquifer. The field has been in production for 20 years, the main production mechanisms are pressure depletion and natural ingress of aquifer water. For the next phase of development a vertical pattern steam flood re-development is planned which will increase the ultimate recovery significantly. The extreme thickness of the heavy oil reservoir is unique for steam floods and poses both opportunities as challenges. There are no direct analogues and the normal practices of managing a steam flood need to be verified and adjusted. For that reason a range of numerical tools has been developed.

The tool box consists of: 1) An explicit well bore model to understand e.g. the internal well fluid dynamics and heat exchange between tubing, annulus liquids and reservoir fluids at the reservoir level as well as the overburden. Particular interesting is the impact of cool aquifer water inflow on condensation of steam in the annulus and near well bore area. 2) Radial models for detailed analysis of recently performed steam soaks. 3) Sector models (1/12 pattern) for capturing overall steam flood performance and to understand the impact of fine scale reservoir heterogeneity, 4) A single pattern model for analysis of the ongoing steam flood trial in the field and 5) A 10- pattern model cut-out of the geological model for understanding of pattern interference and impact of major reservoir features like faulting and structure. The models have been constrained by the long production history of the field. The performance of the tools is illustrated by the work-out of some specific well and reservoir management examples.
Polymer Injection in Heavy Oil Reservoir under Strong Bottom Water Drive
Authors: Al Azri N. , Jamal E. , Murshidi A. , Al Mahrouqi A. , Al Busaidi I. , Kazzaz A. , Al Ajmi W. , Ramalingam S. , De Kruijf A. , Al Kharusi B. , Brooks D.
Published: July 2010

Implementing Enhance Oil Recovery techniques in heavy oil reservoirs with strong bottom water drive has been a challenge in the oil industry. This paper describes an Enhanced Oil Recovery process in which polymer is injected into a clastic reservoir with a strong bottom aquifer drive bearing heavy-oil (250-500 cP). The high reservoir permeability (2-5 Darcy) enables stretching the viscosity limit of a standard polymer application.

The presence of a strong bottom aquifer maintains high reservoir pressure, which could provide a challenge to injectivity. The close proximity of injectors to the oil water contact reduces the efficiency of the polymer flood through water fingering, and polymer loss to the aquifer. To best understand details of the influence of aquifer on the recovery process, test different development scenarios and address key uncertainties, detailed simulation study was conducted. The simulation results showed that the optimum development concept which would help reduce impact of polymer loss to the aquifer would be to utilize the currently existing and future horizontal producers, augmented with additional infill horizontal injectors placed approximately mid-way in the oil column. Optimization of the development was performed using the simulation model where the polymer viscosity, slug size, and injector location were optimized for net present value.

Uncertainty analysis using the simulation model showed that factors such as poor injectivity, poor conformance control and high kv/kh ratio have negative impact on process efficiency. To address and mitigate these key risks and uncertainties a number of activities are underway. These activities include intensive laboratory tests, field injectivity test and a field trial where polymer is injected in newly drilled injectors. The paper discusses study to identify the optimum development concept, key uncertainties and associated risk reduction activities. Finally, this paper discusses the design and the surveillance aspects of the upcoming field trial.
Application of Novel Chemical and Mechanical IOR Techniques to Northwest Louisiana Fields
Authors: Reynolds Jay C. , Berger Paul
Published: July 2010

The Nacatoch B formation in the Caddo Pine Island oilfield is a semi-consolidated, massive blanket sand containing 20–22 API gravity oil with an active water drive prone to rapid radial matrix coning. The area has been very intensively drilled with well spacings as high as seven per acre affording excellent mechanical access to the reservior.

Chemical IOR in combination with an innovative, one man deployable, corrosion-proof production system requiring no workover rig was employed to allow rapid evaluation of reservoir response to the chemical treatment employed.

Analysis of oil and water was conducted and the surfactant SS 1688 from Oil Chem Technologies was chosen for this set of trials.
The Impact of Daily and Seasonal Cycles in Solar-Generated Steam On Oil Recovery
Authors: van Heel A. P. , van Wunnik J. N. , Bentouati S. , Terres R.
Published: July 2010

Steam-injection projects located in areas with abundant sunshine can exploit solar energy to generate steam, instead of burning gas. Using mirrors, sunlight can be concentrated and used to heat water flowing inside a pipe to steam-temperature at high pressure. This solar-generated steam is only available during the day, causing a day-night cycle in the steam-rate, and is also affected by seasonal variations in solar energy, causing a summer-winter cycle in the steam-rate.

Using both analytical modelling and thermal reservoir simulation, we investigate the impact of the daily and seasonal cycles in steam rate on oil recovery. We compare the oil recovery from solar-generated steam and the recovery resulting from a continuous and constant-rate steam-injection, as obtained by burning gas, for instance.

Our analytical model for the periodic heating of matrix-blocks in a fractured reservoir shows that for fractured reservoirs with a typical fracture-spacing larger than one metre, the impact of daily cycles in steam-injection can be ignored.

Using thermal reservoir simulation, we also compare oil recovery from two representative models of realistic reservoirs: a fractured reservoir (recovery mechanism: thermally-enhanced gas-oil gravity drainage) and a non-fractured reservoir (recovery mechanism: steam-drive), for both steam-injection profiles: constant-rate and cyclic-rate. Our simulations show that the seasonal cycles in the solar-generated steam rate are reflected as seasonal cycles in the oil-rate.

The simulation results indicate that for the same cumulative amount of steam injected (during the same time-span), the oil recovery from solar-generated steam-injection and that from constant-rate steam-injection are essentially the same, both for the fractured reservoir and for the non-fractured reservoir. Therefore, from a subsurface oil-recovery point of view, solar-generated steam provides a viable alternative to constant-rate steam-injection.
Investigation of ASP Flooding Efficiency on Artificial Sandstone Cores: Homogenous Case
Authors: Al Shahri H. , Liu J. , Liu K. , Clennell M. B.
Published: July 2010

This work is a part of a fundamental study investigating the efficiency of the alkaline- surfactant-polymer (ASP) flooding process. While heterogeneity in pore structure is a key concern of our research, it is necessary first to have a clear understanding of the baseline behavior when porosity, permeability and throat size are tightly controlled. This control was achieved by manufacturing a homogenous carbonate-cemented sandstone using the calcite in-situ precipitation system (CIPS). We present the multiphase flow properties of the artificial CIPS rocks, including previously unpublished results on oil/water capillary behavior and relative permeability.

In the core flooding experiments described here we used zero clay content and kept the same throat size and pore size distribution and kept the same chemical composition of the ASP slug. The polymer that was used in the flooding was polyacrylamide (1560 ppm) and the surfactant was alpha olefin sulfonate (1% w/w) and the alkaline was NaOH (0.5% w/w). Along with ASP floods, two surfactant floods were run with concentrations of 1% and 0.1% (w/w). Two identical specially fabricated CIPS carbonate cemented cores were used. The silica grains of both cores are primarily silica cemented by calcite. Both cores have a permeability of 1.8 Darcy and porosity of 19.4%. The only experimental variable was then the oils type and we choose oils such that their viscosities have close values. Australian heavy crude oil (18 API) and highly refined paraffinic oil (Ondina 68) were used in the core flooding study.

Two ASP floods were run, and although all the physical parameters were kept same except oil type, the outcome was significantly different. While recovery of both the refined oil and the crude oil was the same after initial waterflood, the crude oil was mobilized more by the ASP process, through both microemulsion and banking processes. The experiment with the refined paraffinic oil produced less ultimate recovery, and only the microemulsion process was significant.
Early Miscible Hydrocarbon Gas Injection in Abu Dhabi Heterogeneous Carbonate Reservoir
Authors: Dawoud Ahmed , El Mahdi Ahmed , Bidinger Curt , Basioni Mahmoud , Ayoub Mohammed , Al Shehhi Abeer Saleh , Khoori Suaad Abdulla
Published: July 2010

Development studies of a heterogeneous carbonate reservoir in Abu Dhabi-United Arab Emirates based on 10 years of data from eight oil producers and one pilot water injection well concluded that mobility enhancement of the injected phase would be a key factor of effective pressure support and recovery. Development studies of different options concluded that miscible hydrocarbon gas injection would give the highest recovery and was adopted for implementation.

Variation of the reservoir fluid properties with presence of a gas cap at the crest was reported and the Minimum Miscibility Pressure (MMP) of the injected miscible hydrocarbon gas reported to be very close to the reservoir pressure. Simulation studies indicated that miscibility would not be sustained and gas percolation into the gas cap would always be there. The studies concluded that gas injection near the OWC would give better chance to benefit from gravity segregation of the percolated gas.

Five spot inverted pattern at the crest in the area below the gas cap and staggered line drive WAG down flank in the highly under-saturated oil were selected as the optimum development option that was implemented in Phase I development area. All the development wells were completed using long radius open horizontal hole completion technique for both the producers and injectors. Hydrocarbon associated gas was processed and injected in its rich composition.

Collected bottom hole samples after one year and half of injection indicated arrival of the miscible front into location of a newly drilled well offset to a gas injector suggesting successful miscibility. Project has been in progress achieving the target production plateau with some anomalies of high GOR. Surveillance plan was set to closely monitor front movement of both gas and water in key observation wells.

This paper presents a case history of an early miscible hydrocarbon gas injection project in a newly developed heterogeneous carbonate reservoir and observations after four years of production and injection.
Modified SAGD In Multiple Zones At Mukhaizna
Authors: Malik Sanjeev , Zhang Y. M. , Al Asimi Mohammed , Gould Thomas L.
Published: July 2010

The Mukhaizna heavy oil field in the Sultanate of Oman has three distinct zones that need steam injection to enhance oil recovery. A new geocellular based reservoir description was prepared as the starting point to evaluate the performance of these three zones; UG2A, UG2B, and MG to different injector and producer configurations. The major challenge was to ensure good production rates without compromising recovery efficiency. The three zones are separated from each other except in a few places where the two zones UG2A and 2B communicate.

During the flood design, producers with horizontal laterals were considered for each of the three zones. However, determining a method for steam injection that delivered recoveries similar to steam assisted gravity drainage (SAGD) was a challenge. A thermal reservoir simulation model was used to evaluate various configurations including horizontal and vertical injectors.

The final design called for commingled vertical injectors positioned between offset horizontal producers with three laterals stacked vertically. This design created a new modified SAGD recovery process for the reservoir. A steam chamber is created above each horizontal lateral, but the steam arrives from the side. One advantage of this design is the ability to control steam in each vertical injector. With advanced surveillance techniques to determine locations of early steam breakthrough, vertical injectors can be controlled to optimize recovery.

This paper will show the design options considered and their estimated recovery. Then the modified SAGD design, implemented at Mukhaizna, will be compared to current production performance in a selected area of the field which has been under injection for around 2 years. Field performance, which will be presented as rate versus time, and, also using dimensionless plots is tracking the thermal model based design quite nicely. The use of surveillance methods to control injection is also discussed.
Integrated Usage of Surveillance Data for Estimating Cap Rock Integrity and Heat Distribution during Steam Injection in a Fractured Carbonate Reservoir
Authors: Schoofs S. , Lawati M. , Engen G. , Salmi K. , Quseimi I. , Kindy F. , Marsden C. , Ita J. , van der Heyden F. H. , Bauer A.
Published: July 2010

EOR operations involving steam injection lead to heat being transferred to the reservoir, which expands, and the expansion is transferred to the overburden. This can induce a cap rock breach and steam/gas seep, leading to inefficient development and higher recovery costs. Thermal expansion could also re-activate faults, potentially affecting surface facilities. In a forward-modeling study of the cap rock integrity during steam injection in a giant fractured carbonate oil field in Oman the possible failure mechanisms of the cap rock were illustrated. Further, opportunities for cap rock and reservoir surveillance were identified. During a first phase steam development of the field a variety of well and reservoir surveillance data are being gathered, including (GPS and InSAR) surface deformation measurements, micro-seismic activity, and (distributed) temperature and saturation logs. Integrated usage of the surveillance data allows for calibration of and comparison between two geomechanical models. The geomechanical models are employed to monitor the cap rock integrity during the steam operation on a regular basis, and to derive the heat distribution (evolution) within the reservoir. To this end, both forward and inverse modeling workflows have been developed. The results of this study may trigger the development and evaluation of alternative steam injection schemes (well spacing, injection rates).
Novel Methodology for Full-Field Production Forecasting in a Large Steamflood Project in Sultanate of Oman
Authors: Wang Wei , Zhang Eamon , Fitchen Bill
Published: July 2010

Full-field production forecasting is a key requirement for facilities design and economic analysis during development of a Field Development Plan (FDP). However, forecasting using relatively fine-grid thermal simulation models with over one million grid blocks can require days or weeks to complete a run. Within the timeframe of a typical FDP project, teams must often evaluate multiple geologic and reservoir engineering scenarios, development concepts, and uncertainty ranges in high- sensitivity variables in terms of their impact on production streams, costs, and overall project economics. During this evaluation process, fast and flexible forecasting methods are favored over slower but perhaps more accurate methods.

Mukhaizna field is a giant heavy oil field in South Sultanate of Oman and is presently under steamflood. Following a period of cold production development involving the drilling of 75 horizontal producers and resulting in very low recovery, a steamflood FDP was developed over a period of six months. Based on this FDP, drilling of hundreds of horizontal producers and thousands of vertical injectors is planned for the next 20 years. Mukhaizna is the first large-scale commercial steamflood to use horizontal producers and vertical injectors.

Full field production forecasting for Mukhaizna was performed using a novel, fit-for-purpose workflow. Pattern-scale, fine- grid geologic models representing areas of distinctive flow unit and permeability architecture were built and simulated to develop pattern production type curves. Full-field production forecasts were obtained by scaling up production streams from type-curve simulation using a scale-up tool prototyped in Excel. Inputs to the scale-up tool included pattern STOOIP, drilling sequence/schedule, production targets, and facilities constraints. Once type curve simulation was completed, any field development scenario could be forecasted within a few hours. This paper 1) describes how the type-curve models were defined, generated, and simulated; 2) how the detailed scale-up methodology was developed and applied in the Mukhaizna FDP.
Case Study of Alkali - Polymer Flooding with Treated Produced Water
Authors: Yang De-hua , Wang Jian-qiang , Jing Li-xi , Feng Qing-xian , Ma Xian-ping
Published: July 2010

It is very challenging to run polymer/alkaline flooding in a high water-cut (Sw>96%) and viscous oil (μ:114mPa.s at 60°C) reservoir using produced water to mix chemicals. This work is aimed at applying Alkili-polymer flooding under a circumstance there is a shortage of fresh water supply. The selected chemicals are compatible to hard components such as Ca and Mg in the produced water. A less polymer solution degradation in the treated produced water is obtained. A pilot test program was carried out in Yangsanmu oilfield from 1998 to 2008.

During the pilot test, based on lessons obtained, a series of new technologies were developed (1) to reduce active composition and in produced water, the produced water was air-bubbled extensively and improved water quality. (2) Removed chemicals the produced water was filtered using sandy filter. (3) using anti-salt polymer to replace previous used pyacrylamide to increase polymer solution viscosity. (4) using active alkaline to replace dicarbonate on high acid value oil (1.84mgKOH/g oil). As a result, the IFT decreased from 0.1 to 0.001 mN/m and no more crust. The core test showed that the oil recovery by selected alkali-polymer solution increased 22.8% even we started it at a water cut of 90%. The optimized chemical system is 1% alkaline plus 0.15% polymer.

The pilot was run with a test area of 0.71km2, including 4 injectors and 18 producers. The solution was prepared in a central station and delivered to injectors by pipelines. Total injected polymer solution was 1.1 million cubic meter with concentration 0.15%, and alkaline solution was 0.72 million cubic meter with concentration 0.8%. About 6 moths later, dynamic monitored residual oil saturation with fiber glass casing in 2 producers showed the residual oil decreased from52.8% to39.6%. Injecting pressure increased by 2MPa and water cut decreased from 96.4 to 71.6%. The total oil incremental reached 0.94 million bbl.
Modeling Formation Damage due to Flocculated Asphaltene Deposition through Dynamic Displacement
Authors: Rezaian A. , Kordestany A. , Jamialahmadi M. , Moghadasi J.
Published: July 2010

The deposition of asphaltene in porous media and their interaction with rock and fluids represent complex phenomena which needs to be investigated under dynamic flowing condition. It could occur by reducing mobility (λ=k/μ) in three probable mechanisms of asphaltene included damage: a) blocking pore throat, b) altering wettability, and c) increasing the reservoir fluid viscosity and can have strong effect on oil production through heavy oil recovery, miscible flooding, and even primary recovery. Many experiments were performed by researchers to determine the amount of deposition and permeability decline but the boundaries in which the asphaltene deposited in oil or at the pore surface was not determined, thus the models introduced have some difficulties using all parameters.

In this paper, a mathematical model is developed constructing to simulate rock-fluid interactions describing permeability decline due to asphaltene deposition. The model considers the second stage (if separated into liquid phase precipitation and pore surface deposition) of asphaltene deposition in which n-hexane used to flocculate asphaltene particles in order to determine the effect of deposition on sandstone rock due to changing of pressure, temperature, and composition of reservoir oil. The influences of various injection rates and concentrations are considered carefully.

This model simulation and corresponding analytical method is applied using laboratory data gained by performing various dynamic displacement experiments with pre-separated oil asphaltene content resulted a close agreement so it could predict the trend of permeability reduction due to deposition of asphaltene. So the procedure of matching the parameters is described here.

This model can be used for analysis of laboratory core tests of formation damage due to flocculated asphaltene particles. Thus, the present study leads to a new insight into the mathematical explanation of flow behavior in porous media.
Probabilistic History Matching With the Capacitance-Resistance Model in Waterfloods: A Precursor to Numerical Modeling
Authors: Sayarpour M. , Kabir C. S. , Sepehrnoori K. , Lake Larry W.
Published: July 2010

Several equally probable sets of uncertain reservoir parameters can normally match a production history. Such equiprobable history-matched solutions (EPHMS) are a way to estimate the uncertainty in hydrocarbon-recovery predictions. Ordinarily, time and resource limitations permit evaluation of only few of the EPHMS, thereby reducing reliability of predictions of numerical models. As a precursor to comprehensive numerical simulations in a probabilistic frame, we suggest the use of capacitance-resistance model or CRM. In CRM only injection and production rates are needed.

The CRM is a fast analytic tool for history matching and optimizing waterfloods. In this study, we used CRM and a Buckley-Leverett-based fractional-flow model to rapidly generate many EPHMSs. The EPHMS represent a unique combination of major reservoir variables, such as residual saturations, endpoint mobility ratio, oil and water in-place volumes, and recoverable oil.

We used production data from two matured waterfloods and a synthetic field (Synfield) to evaluate the EPHMS. For most cases, one thousand EPHMS and the consequent cumulative distribution functions (CDFs) for several uncertain variables, including recoverable oil, were developed. We compared the CDFs obtained from EPHMS to that of 200 finite-difference simulations performed on the Synfield by changing porosity and residual saturations. EPHMS mimicked the same uncertain range of production forecasts used earlier in the finite-difference model. This approach attested to the goodness of CRM solutions and its ability to quantify reservoir uncertainty. Two field examples illustrated applications of the proposed approach at the field and pattern levels, and provided clues about the remaining oil and its monetary value.
Microbial EOR—Critical Aspects Learned From The Lab
Authors: Jackson Scott C. , Alsop Albert , Choban Eric , D'Achille Ben , Fallon Robert , Fisher John , Hendrickson Ed , Hnatow Linda , Keeler Sharon , Luckring Abigail , Nopper Rick , Norvell Joseph , Perry Michael , Rees Bethany , Suchanec David , Wolstenholme Sheryl M. , Thrasher Dave , Pospisil Gordon
Published: July 2010

DuPont and BP have been working together to develop Microbial EOR targeted at viscous oil in the Schrader Bluff formation on the North Slope of Alaska. The goal of this program was a 5% increase in the recovery factor. Mechanisms to be assessed in the original agreement included Viscosity reduction of the oil by transformation or degradation of heavy components in the oil – thus improving the oil – water mobility ratio.Drastic reduction (to ~<0.01 dynes/cm) in the interfacial tension between water and the oil

After extensive fundamental research we have learned many critical aspects of microbial EOR that made the application of these two mechanisms to the Schrader Bluff formation impractical. Instead, we have demonstrated two site appropriate mechanisms that achieved, in the lab, the targeted increase in the recovery factor. Improved flow conformance and increased sweep efficiency by preferential plugging of high permeable zones thereby forcing water to produce oil from previously unswept parts of the reservoir.Reduced oil / rock surface tension and a subsequent reduction in the oil "wetting" the rock. This results in changes in the relative permeability of the oil and the water and ultimately lower residual oil saturation.

This paper describes the key laboratory tests used to evaluate these four mechanisms. The cornerstones of our work have been the detailed characterization of the waters, the oil, the formation matrix and the microbial community. In addition we describe our search for useful microbes isolated from a variety of environmental samples collected from the Milne Point Unit (MPU) of the Alaskan North Slope. These samples were taken over several years and included injection, production and power fluid waters. These samples were used to understand the temporal changes in the microbial populations and to provide inoculum for our enrichment cultures.

Our ongoing research has provided many insights into the appropriate application of microbial EOR. The unique aspects of each production area, the nature of the oil, the water, the formation matrix, and the background microbial population and their complex interactions must all be assessed when considering the potential application of microbial EOR. The amount of work discribed below for assessing potential MEOR mechanisms is extensive. However, this process has been streamlined and we have been able to assess new target reservoirs for potential MEOR treatments in about 6 months.
Reservoir Simulation of Steam Fracturing in Early Cycle Cyclic Steam Stimulation
Authors: Cokar Marya , Kallos Michael S. , Gates Ian D.
Published: July 2010

In Cyclic Steam Stimulation (CSS), steam is injected above the fracture pressure into the oil sands reservoir. In early cycles, the injected steam fractures the reservoir creating a relatively thin dilated zone which allows rapid distribution of heat within the reservoir without excessive displacement of oil from the neighborhood of the wellbore. Numerical reservoir simulation models of CSS that deal with the fracturing process have difficulty simultaneously capturing flowing bottom hole pressure behaviour and steam injection rate. In this research, coupled reservoir simulation (flow and heat transfer) and geomechanics models are investigated to model dynamic fracturing during the first cycle of CSS in an oil sands reservoir. In Alberta, Canada, in terms of volumetric production rate, CSS is the largest thermal recovery technology for bitumen production with production rates equal to about 1.3 million bbl/day in 2008. The average recovery factor from CSS is between 25 and 28% at the economic end of the process. This implies that the majority of bitumen remains in the ground. Since the mobility of the bitumen depends strongly on temperature, the performance of CSS is intimately linked to steam conformance in the reservoir which is largely established during steam fracturing of the reservoir in the early cycles of the process. Thus, a fundamental understanding of the flow and geomechanical aspects of early cycle CSS is critical. A detailed, thermal reservoir simulation model, including dilation and dynamic fracturing, was developed to understand their effects on bottom hole pressure and injection rate. The results demonstrate that geomechanics must be included to accurately model CSS.
Laboratory Investigations of CO2 Near-miscible Application in Arbuckle Reservoir
Authors: Bui L. H. , Tsau J. S. , Willhite G. P.
Published: July 2010

Carbon dioxide (CO2) is a proven enhanced oil recovery technology. However, many reservoirs are located at shallow depths or geologic conditions such that CO2 can not be injected at pressures above the MMP. CO2 injection is usually not considered as an enhanced oil recovery process in these reservoirs. When CO2 is injected below the MMP, displacement efficiency decreases as a result of the loss of miscibility. Near miscible displacement has sometimes been referred to as the process occurring between immiscible and miscible pressures, but has never been clearly defined. This paper describes laboratory study of CO2 near miscible displacement in an Arbuckle reservoir in Kansas.

Phase behavior studies between CO2 and Arbuckle crude oil were carried out to define near miscible conditions at reservoir conditions. Swelling/extraction tests combined with slim-tube experiments were interpreted to identify the mass transfer mechanisms at near miscible condition. A phase behavior model was developed to match PVT data and MMP in the slim-tube experiment. Good agreement was obtained between simulated and observed data from slim-tube experiments. Core flooding tests were conducted to evaluate oil recovery at near miscible condition at which pressure varies from 1350 psi (MMP) to 1150 psi. Recovery of over 50% of the waterflood residual oil saturation was observed when CO2 was used to displace Arbuckle oil from Berea, Baker dolomite and Arbuckle dolomite cores.

At near miscible conditions, extraction appears to be the primary mechanism for mass transfer between hydrocarbon components and CO2. However, the reduction of oil viscosity by a factor of five occurred when CO2 dissolved in the oil. This suggests that some of the additional oil recovery may be attributed to reduction of the mobility ratio between CO2 and resident oil.