Crestal Gas Injection Research Articles

Data Science Enables Management of Stealth Asphaltene Flow-Assurance Risk

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216216, “Managing Stealth Asphaltene Flow-Assurance Potential Risk in Gas-Injection Field Based on Data Science Using Over 20-Year Accumulated Data Set,” by Hideharu Yonebayashi, SPE, and Takeshi Hiraiwa, SPE, Japan Oil Development, and Khuloud T. Al Khlaifi, SPE, ADNOC, et al. The paper has not been peer reviewed. _ Gas injection is recognized generally not only to improve oil recovery but also to increase the risk of asphaltene destabilization. The recent discovery of asphaltene deposits in a subject field motivated the operator to launch an immediate investigation to evaluate what critical risks might exist and consider appropriate mitigation. It was found that precipitated but invisible asphaltenes still can be flowable. This stealth asphaltene behavior could explain a possible mechanism of the first asphaltene observation in the upper reservoir. Introduction The subject giant offshore field in the Arabian Gulf has not experienced asphaltene-induced production deterioration during long-term lean hydrocarbon gas injection. The gas has been injected into the crestal area of two reservoirs (upper and lower) with peripheral powered seawater injection. Both reservoir fluids contain a small amount of asphaltenes (0.1–1.5 wt%) distributed at higher concentration at deeper locations. In May 2022, the first discovery of asphaltene deposits from the historical no-issued area in the upper reservoir motivated an immediate investigation for risk assessment and mitigation. A resulting study captured stealth asphaltenes, which were detected by a laser-light-scattering technique while high-pressure microscopy detected no visible asphaltene solid particles. Historical Asphaltene Data Accumulation The permeability range and pore-throat size of the subject field are relatively low in the lower reservoir compared with the upper. Both reservoirs are under highly unstable asphaltene-stability conditions. The reservoir pressure-maintenance scheme, consisting of dump-floodwater injection followed by peripheral powered seawater injection and crestal gas injection, however, has maintained asphaltene-free production except for the gas-injection pilot (GIP) during 2005–2009. No asphaltenes have been observed in the crestal gas-injection area; however, asphaltene deposits were observed in the GIP area in 2007. The injected gas was enriched gradually by a vaporizing gas-drive process. The previous studies involving numerical modeling analysis and laboratory experiments reported that enriched hydrocarbon gas can more easily allow asphaltene precipitation compared with lean hydrocarbon gas. GIP Asphaltene Risk Analysis (Upper Reservoir). In 2009, an asphaltene flow-assurance risk evaluation was conducted using the single-phase bottomhole sample collected from Well 6, which is 90 ft shallower that the GIP area and far from the crestal gas-injection area. Therefore, the Well 6 reservoir fluid was not affected by injection gas. The bottomhole condition of the GIP production well was entered into the asphaltene precipitation envelope (APE) that was expanded by injection-gas enrichment but never covered by the APE without an enrichment process. Latest Laboratory Analysis (Lower Reservoir). In 2022, an asphaltene flow-assurance risk evaluation was conducted. After the location was narrowed to a depth range, Well 1 was selected by taking an asphaltene gradient into account.

Automated Work Flow Identifies Opportunities for Production, Cost Improvements

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31295, “Automated Reservoir Management Work Flows To Identify Candidates and Rank Opportunities for Production Enhancement and Cost Optimization in a Giant Field Offshore Abu Dhabi,” by Carlos Mata, SPE, Luigi Saputelli, SPE, and Dorzhi Badmaev, SPE, ADNOC, et al. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. _ An intensive effort is required to identify the right candidates and to ensure the technical and economic success of well interventions, infill-drilling locations, and sidetrack locations. An accelerated method for selection of existing wells for workovers and sidetracks would be of great value. A work flow is developed to automate tasks such as data gathering and validation. The solution allows integrated assessment of production-enhancement opportunities through consistent analytic computations and machine-learning techniques including Bayesian networks and time-series forecasting models. Automated Data Integration The advisory system starts with data integration and work-flow automation steps. The system was implemented in the commercial software PetroVisor. The software integrates data points as signals that are tied to entities such as wells. Different relationships with multiple levels can be specified between the integrated entities. The software allows the integration of any legacy data source all along the value chain to topside facility equipment. The advisory system aggregates data from selected entities on different hierarchy levels and incorporates data from more than 400 wells with 700 perforations and 5 decades of production history. The selected field contains two reservoirs, each with three sublayers. Production began with primary depletion. Waterflooding, and then crestal gas injection, began in the early 2000s. Reservoir properties and dynamic data were exported from the latest history-matched reservoir simulation model. The well trajectories and the exported fluid contacts allow the generation of Voronoi grids for each reservoir and layer. The literature refers to Voronoi grids as perpendicular bisection (PEBI) grids. Each gridblock is locally orthogonal. Unstructured PEBI grids are favorable when complex well geometries and geological features are present. Voronoi cells were generated automatically for the layers in the software, where grid-cell boundaries are created and constrained by encountering faults and fluid contacts. Grid nodes represent the wells. An example of a Voronoi cell is shown in Fig. 1. Voronoi grids should be recomputed over time because of the dependency of actual fluid contacts and active wells. It is recommended to regenerate them whenever a recently history-matched model is available. After generation of grids, exported reservoir and fluid properties can be assigned to each node. The spatial properties can be upscaled locally within each cell, allowing prompt evaluation of original oil in place (OOIP) and remaining oil in place of grid cells.

Data-Driven Analytics Provide Novel Approach to Performance Diagnosis

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 192759, “Data-Driven Analytics: A Novel Approach to Performance Diagnosis Using Spatiotemporal Analysis in a Giant Field Offshore Abu Dhabi,” by Mohamed Mehdi El Faidouzi, SPE, and Djamel Eddine Ouzzane, ADNOC, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed. This work describes a heuristic approach combining mathematical modeling and associated data-driven work flows for estimating reservoir-pressure surfaces through space and time using measured data. This procedure has been implemented successfully in a giant offshore field with a complex history of active pressure management with water and gas. This practical work flow generates present-day pressure maps that can be used directly in reservoir management by locating poorly supported areas and planning for mitigation activities. Field Overview The giant oil field offshore Abu Dhabi covers an area of approximately 40×25•km. The structure is a low-relief anticline. The fault pattern is dominated by steep northwest/southeast strikes, with less-abundant northeast/southwest strikes. The fault throws are generally small, and most faults are unlikely to be sealing laterally. The oil accumulation is separated by dense argillaceous limestones into three distinct, stacked reservoirs (A, B, and C), each approximately 20 to 35 ft thick. Formation-pressure tests showed good intrareservoir vertical pressure communication. Occasionally, especially toward the north and east, a generally tight clay-prone lithology forms a localized barrier between the upper and basal layers of Reservoirs A and B. The complete paper examines the case of the upper layers of Reservoir A in particular, a laterally extensive porous carbonate deposited in a shallow-water environment, although the work flows developed are equally applicable to other reservoir zones. Commercial production of Reservoir A began in the late 1960s. After an initial period of natural depletion, various pressure-maintenance strategies were deployed, namely dump-flood (1972–1984), peripheral water injection (from 1979), and crestal gas injection (from 2005). Spatiotemporal Analysis of Pressure Data Prediction of spatial random fields is a common task in geostatistics and arises in geology, mining, hydrology, and atmospheric sciences. Kriging procedures are used routinely to make optimal predictions at unsampled locations. For quantities that vary in space and time, such as reservoir pressure, spatiotemporal interpolation can provide more-accurate predictions than purely spatial interpolation because observations at other times are considered. In producing oil and gas assets, reservoir-pressure measurements are made at a much higher frequency in the time domain compared with the spatial domain, which requires additional wells to be drilled. The conventional approach of using a spatial interpolation on the basis of a certain time period misses valuable information and could result in inconsistencies between maps from one time period to the next. In this case study, the authors present a heuristic approach to estimating reservoir pressure maps in Reservoir A on the basis of spatiotemporal interpolation. Reservoir pressure is modeled using smooth functions that capture global trends while preserving the spatial and temporal continuity of pressure and pressure gradient. The residuals can be described by a stationary and spatially isotropic process. Residuals then can be predicted at unsampled space and time locations by kriging.

Integrated Approach Overcomes Depleted-Reservoir Challenges

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 28517, “Deepwater Extended-Reach-Well Planning Through Depleted Reservoirs,” by Beng-Hooi Shi, Jennifer Koh, Dexter Liew, and Guat-Lee Chio, Shell, prepared for the 2018 Offshore Technology Conference Asia, Kuala Lumpur, 20–23 March. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage. Because of the depleted nature of all three reservoirs located above the untapped reservoir, a need exists to drill through these depleted intervals with an extremely narrow margin window (less than 0.5 lbm/gal). An added complexity is the location of the reservoir, directly below a hydrates bulge. To address the challenges of this well, an integrated approach between various disciplines has proved to be a critical success factor. Introduction The field is offshore Sabah. The first phase of the development was completed in 2014, with 16 wells drilled. The development includes gas reinjection and seawater injection. The hydrocarbons are trapped in a four-way dip closure developed in an anticline structure containing four sand reservoirs separated by sealing shale layers. The Phase 1 development targeted the two main reservoir units (B and C) in the middle of the four reservoir sands. The pressure maintenance for the development of these two main reservoir units is provided by a combination of downdip water injection in the water leg and crestal gas injection in the gas cap. The second phase, comprising two oil producers and two water injectors, aims to maintain the oil-production plateau. One of the Phase 2 objectives is to target the deepest untapped reservoir (D) in the field with Well 4. However, as mentioned previously, Well 4 must drill through depleted intervals with extremely narrow drilling margins. Two of the four wells (Wells 1 and 2) only will drill into the depleted B reservoir in the final reservoir hole section, while the third well will cross the depleted B reservoir before drilling into the depleted target reservoir, C, in the final hole section. Phase 2 will offer the opportunity to acquire further data. Because of the stacked arrangement of Reservoirs A, B, C, and D and the wells targeting different reservoirs, a possibility exists to sequence the drilling campaign in a batch mode and to use data acquisition, operational learnings, and prediction validation before committing to drilling the intermediate and reservoir sections of the most difficult well (Well 4). The projected formation pore pressure and fracture gradient (PPFG) poses significant drilling challenges because of depletion plus the geomechanical requirements. The Reservoir C water injector is predicted to have a limited drilling margin because of the depletion of Reservoir B.

4D Seismic Pilot Successfully Interprets Carbonate Reservoir

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193063, “A Successful 4D Seismic-Monitoring Pilot in a Middle East Carbonate Reservoir Context,” by F. Cailly, T. Al-Romani, C. Hubans, and A. Lafram, Total, and A. Al Kaabi, ADNOC, prepared for the 2018 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11–14 November. The paper has not been peer reviewed. This paper describes interpretation results of a 4D seismic-monitoring program in a challenging Middle East carbonate reservoir. The program consists of a 4D pilot [oceanbottom cable (OBC)] over a giant field divided into two phases. The authors discuss the difficulties faced by both phases of the pilot, and prove that a reliable 4D signal can be extracted over a Middle East carbonate reservoir. Introduction The time-lapse, or 4D, seismic method consists of repeating seismic survey acquisitions over the production time of a field. Newer vintages are compared with previous ones, and the signal differences are interpreted to characterize effects of the production spatially. Though this technique is mature and has been widely used in clastic reservoir environments, it is still used rarely, in operational terms, to monitor carbonate fields. An opportunity for a 4D proof-of-concept program in a Middle East marine carbonate environment was identified during a new OBC seismic acquisition in 2013. While the survey was intended for 3D imaging purposes, the operator decided to acquire a 4D pilot over a test area of approximately 25 km2 (Phase 1) while repeating as best as possible the 1994 acquisition design (baseline for this 4D study). The goal was, first, to process this test, and then, if a reliable 4D signal (above noise level) could be established, to propose interpretation in accordance with the field-production mechanisms. Field-Production and 4D Monitoring Objectives The principal oil-producing reservoir belongs to the Upper Jurassic and is a mixture of limestones, dolomite, and anhydrite. It contains the primary 4D monitoring target for this pilot. First oil was produced in the 1960s, followed by peripheral water injection in the 1970s and crestal gas injection in the 1990s. Thus, the 1994 4D baseline survey is an OBC seismic acquired after a rich and complex production history. Four-dimensional monitoring is justified by the fact that many expensive wells are drilled every year and their positioning is not straightforward. In particular, the crucial fluid-movement prediction (gas and water) is challenging and, thus, is considered the main monitoring objective. Phase 1 Acquisition Status Repeating baseline acquisition parameters during the monitoring survey is crucial. Any deviation from this principle is likely to generate a 4D noise that will be difficult to remove. In this pilot, taking advantage of a seismic crew mobilization for a modern wide-azimuth OBC acquisition, the field operator decided to try to repeat, in a small patch, an older OBC survey as a 4D pilot. In fact, this legacy vintage, which has a very different narrow-azimuth design, only was repeated over three swaths. The geometrical repeatability was good, except in the obstruction areas.

Optimum development options and strategies for water injection development of carbonate reservoirs in the Middle East

Abstract Through the research on several carbonate reservoirs developed in the Middle East, the basic characteristics of different types of carbonate reservoirs are determined, and a set of high-efficiency water injection development options and strategies are presented. Hidden baffles and barriers exist in carbonate reservoirs in the Middle East, so the reservoirs could be divided into different separated development units based on the baffles and barriers characteristics. Flexible and diverse profile control techniques such as high angle wells and simple and applicative zonal water injection have been introduced to improve the control and development degree of reservoirs. Three principal water injection development methods suitable for different carbonate reservoirs in the Middle East are proposed, including the combination of crestal gas injection and peripheral water injection, bottom interval injection and top interval production (buoyancy underpinning), and “weak point and strong plane” area well pattern. Based on the characteristics of very low shale content, fast and far pressure transmission in the Middle East carbonate reservoirs, a large well-spacing flood pattern is recommended, and reasonable development strategies have been made such as moderate water injection rate and maintaining reasonable production pressure drawdown and voidage replacement ratio, so as to maximize the recovery of reservoirs in the none or low water cut period.

Gas Tracers: A Decade of Learning and Experience

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183413, “A to Z for Gas Tracers: A Decade of Learning and Experience,” by M.N. Khan, H. Iwama, A. Al-Neaimi, and O. Al-Shehhi, Abu Dhabi Marine Operating Company, and M. Chatterjee, Tracerco, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed. In interwell tracer studies, reservoir complexities often make tracer-breakthrough time difficult to assess. Although reservoir-simulation studies serve as an effective tool in predicting a breakthrough, the tracer behavior in the real porous media sometimes presents intriguing surprises. This paper discusses a crestal gas-injection project that was carried out in a supergiant heterogeneous-carbonate oil field. Introduction A tracer-survey study can provide a variety of information about the heterogeneity of a formation. While transient tests can provide information about reservoir continuity, thief zones are difficult, if not impossible, to detect. This is because pressure-transient tests provide an arithmetic average for reservoir total transmissibility over the tested formation thickness, while a tracer survey provides a direct evaluation of the flow field between the injection and production wells. Apart from heterogeneity, tracer studies also serve as an informative tool to yield fluid-flow paths inside the reservoir, popularly known as reservoir streamlines. A tracer survey not only can precisely identify these preferential paths that are detrimental to the sweep of the reservoir in the enhanced-oil-recovery stage but also can provide information about the time that fluid takes to move from one point (injection well) to another point in the reservoir. This time is termed the mean residence time. In addition, any flow barrier or directional thief zones such as faults can be identified by delayed tracer recovery. The mass-balance technique can be used to calculate the amount of tracer recovered to distinguish between the existence of a fault, a flow barrier, or a low-permeability zone. Tracer-Project Design Interwell tracer testing consists of injecting chemical tracers into injection wells at the beginning of a flood project or after the reservoir has reached its fill-up condition, depending on the objective of the project, and subsequent sampling of production wells for a prescribed period of time, which also depends on the objective of the project. Samples are analyzed for tracer content, which will delineate communication between the injection and production wells. The time during which samples are collected and analyzed depends greatly on the objective of the project. If the objective is to identify thief zones, deduce mean residence time, and determine other factors that could lead to full-field reservoir characterization that could be fed directly into a simulation model, sample collection and analysis must continue for a considerable period of time after tracer is first detected in order to establish a more-defined elution curve.

A New Gas Injection System for Ultra-Thick Metamorphic Rock Buried Hill Reservoirs

This article proposes a new gas injection system that is a kind of tridimensional gas injection mode applied in the middle-lower part of the reservoir during the process of gas injecting on the reservoir top, which is suitable for the tridimensional reservoir development[1-2]. This system can express the gravity-stable drive effect on the crestal gas injection as well as the effective using of waterflooded wells to form continual micro gas/water slug drive naturally, supply the producing energy timely, diminish the water sealing of waterflooded reservoir matrix, enhance the gas dialysis on fine crack and microscopic sweep efficiency and control the water content, thus improve the production rate and enhance the recovery. Tridimensional gas injection system has been verified by physical simulation and numerical simulation. Pilot testing on Xinggu 7 buried hill reservoir has acquired an actual effect to increase the oil production, boost the pressure and decrease the water cut. Key words: Tridimensional; Gas injection system; Ultra-thick reservoir; Buried hill; Gravity-stable drive; Waterflooded well

Integrating Well, Reservoir, and Facility Management Improves Field's Production

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 16523, ’Oman's Large-Carbonate-Field Production Improvement Through Integrated Well, Reservoir, and Facility Management,’ by S.M. Al-Khadhuri, M.M. Al-Harthi, and A. Alkalbani, Petroleum Development Oman, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. A carbonate field developed by Petroleum Development Oman is one of the largest fields in the Sultanate of Oman and has been running for more than 4 decades. An integrated wells, reservoir, and facility management approach has been implemented to create more focus and discipline with the aim of achieving an efficiently monitored and controlled asset and highly synchronized multiteam actions. Introduction The field is located in the north of the Sultanate of Oman, and it is one of Oman’s largest fields. The reservoir layers dip uniformly at 15° to the northeast (Fig. 1). The field is a highly complex carbonate reservoir of the Natih formation and is subdivided into seven units, Natih A through Natih G, and the Shuabia reservoir. It has been running since 1967 and continues to contribute significantly. The development strategy began with natural depletion with vertical wells and followed with two mechanisms, gas/oil gravity drainage (GOGD) and waterflood. The GOGD process concentrates more on fractured reservoir rock, while the waterflood process targets the layers with a relatively low degree of fracturing. The GOGD development consists of five crestal gas-injection wells and rows of down-flank producers that tap oil from a fractured oil rim. The reservoir pressure is managed by gas injection. The gas-injection rates are set to replace voidage and to maintain reservoir pressure. For the matrix wells, the reservoir pressure is managed by waterflood (water injection). This combination of different drive mechanisms in a highly fractured reservoir that yields to interference and gas/water short-circuiting makes the management of the field very challenging. To overcome these challenges, an integrated well, reservoir, and facility management strategy has been established in a way that ensures integration with multiple disciplines and uses many tools. As a result, an improvement in production has been seen that reflects successful implementation of the strategy. Wells and Reservoir Reviews Wells are reviewed on a yearly basis in order to have a systematic approach for reviewing wells. Approximately 26 sectors (more than 450 wells) from different reservoirs have been reviewed collaboratively. Multidisciplinary involvement from the well and reservoir management (WRM) team, the development and planning (DP) team, and the new oil (NO) team, and alignment to mature identified activities, played a crucial role in effectively sharing ideas and lessons learned and implementing activities.

Realizing Value From Implementing i-field™ in Agbami—A Deepwater Greenfield in an Offshore Nigeria Development

Summary Digital oil field (DOF) in the upstream industry has gained momentum in the last few years and has transformed from being solely a vision to actual projects that have measurable value. The ultimate goal in DOF projects is an integrated approach toward decision making and control of asset management in relevant time. This paper describes the successful methodology adopted for implementing the i-field™ program (i-field is a trademark of Chevron Corporation) in Agbami—namely, identification, prioritization, and implementation of relevant workflows. The Agbami field, located in deepwater offshore Nigeria, is a subsea development that incorporates crestal gas and peripheral water injection. It is located in approximately 1500 m of water depth and consists of a 38-well development program to be implemented in three phases. The well completion incorporates intelligent well completions (IWCs)—downhole flowmeters, pressure and temperature gauges, and interval-control valves (ICVs). These downhole accessories are managed using electric and hydraulic controls/instrumentation, with subsurface, subsea, and topside data acquired and transmitted to a central data historian on the floating production, storage, and offloading (FPSO) unit in relevant time. The implementation of a robust architecture for a data- and informationmanagement system involving acquisition, processing, storage, and replication (from offshore to onshore) is conceived to be the foundation upon which asset-management workflows are implemented. The expected benefits from implementing the i-field program in Agbami include reduction in lost production opportunity (LPO) through proactive asset management, better long-term reservoir management through time-line management of injection- and production-rate balancing, increased efficiency and reliability through guided workflows, improved ultimate recovery, and better overall performance from standardization of base business work processes. The real value of implementing i-field initiatives in Agbami lies not only in the return on investment but also in providing a benchmark for capturing the value of other assets. Based on field experience, this paper discusses the approach toward value realization of the i-field system, including change-management strategy for end-user acceptance. Critical success factors and lessons learned during deployment are also presented.

Optimization of Smart Wells in the St. Joseph Field

Summary The St. Joseph field has been on production since September 1981 under natural depletion supported by crestal gas injection. As part of a major redevelopment study, the scope for waterflooding was addressed using "smart" completions with multiple inflow control valves (ICVs) in the wells to be drilled for the redevelopment. Optimal control theory was used to optimize monetary value over the remaining producing life of the field, and in particular to select the optimal number of ICVs, the optimal configuration of the perforation zones, and the optimal operational strategies for the ICVs. A gradient-based optimization technique was implemented in a reservoir simulator equipped with the adjoint functionality to compute gradients of an objective function with respect to control parameters. For computational reasons, an initial optimization study was performed on a sector model, which showed promising results.

Numerical Simulation and Sensitivity Analysis of Gas-Oil Gravity Drainage Process of Enhanced Oil Recovery

Abstract The oil recovery process is controlled by the rates of gas injection and oil production, relative permeabilities, reservoir heterogeneities and the balance among viscous, capillary and gravity forces. Crestal gas injection in horizontal, vertical or reef type oil reservoirs recovers significant volumes of the residual oil due to the gas-oil gravity drainage mechanism, indicating the significance of gravity forces. This study investigates the effects of the parameters that control the process (e.g., rate of the gas injection and oil production) and reservoir heterogeneities on the overall performance of immiscible gravity drainage enhanced oil recovery (EOR). Reservoir simulation studies are conducted to map effective combinations of these parameters with respect to the oil recovery performance. Introduction Gravity forces play an important role at nearly every stage of the producing life of the reservoir, whether it is primary depletion, secondary water or gas injection schemes or tertiary enhanced or improved oil recovery methods(1). They can be advantageously used to maximize oil recovery from the oil bearing zone under investigation through gravity drainage mechanism. Several cases reported in the literature suggest that it could deliver as high as 87 to 95% incremental oil recoveries in contrast to other gas injection EOR methods. Gas-Oil Gravity Drainage Process Gravity drainage is a process in which gravity acts as a main driving force and where gas replaces voidage volume(2). It is commonly implemented in either of the dipping or pinnacle reef type reservoirs. CO2-assisted gravity drainage EOR process is a top-down process in which gas is injected in the gas cap through vertical wells at a rate lower than the critical rate (Figure 1). Critical rate is the rate at which injection gas fingers through oil zone (viscous instabilities) leading to its premature breakthrough at the production wells. Injected gas segregates and creates a gas-oil interface. Controlled oil production is started through horizontal wells placed at the bottom of the oil zone such that the voidage created by oil withdrawal (in addition to minor dissolved volumes) is replaced by the equivalent CO2 injection volume. When this happens, pressure differential across the gas cap and oil zone [that is gas-oil contact (GOC)] stay at or close to zero implying that the pressure in the gas zone behind the CO2 floodfront would be constant(3). This helps to maintain the reservoir pressure nearly constant.

Agbami Project: People and Partnerships Deliver a World-Scale Field Development

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20249, "Agbami Project: People and Partnerships Delivering a World-Scale Field Development," by C.D. Bloomer, Chevron Project Resources Company, originally prepared for the 2009 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed. The Agbami project successfully began production in July 2008, 10 years after the discovery of this world-class reservoir. Agbami represents one of Chevron Corporation's largest capital investments of the decade and the project achieved many outstanding results, overcoming various challenges along the way. The full-length paper provides an overview of the project and discusses the key project objectives, strategies used, and some of the lessons learned. Introduction The Agbami field sits 70 miles offshore Nigeria in approximately 5,000-ft water depth. The reservoir is a doubly plunging, thrust-faulted anticline comprising four main reservoirs. The crude is light and sweet, 47°API. The selected development plan includes a floating production, storage, and offloading (FPSO) vessel and subsea well completions. The FPSO has an oil-production capacity of 250,000 BOPD, gas-injection capacity of 415 MMscf/D, and water-injection capacity of 450,000 BWPD. The combined production capacity of the FPSO ranks as the largest in the world. Crestal gas injection provides pressure maintenance for the reservoir as well as preventing routine flaring of associated gas. Peripheral water injection also provides pressure maintenance. An estimated 38 wells eventually will be needed to develop the reserves fully. Nigerian Content The Agbami project made an early decision to achieve a new standard in Nigerian Content. Nigerian Content is a critical government objective to expand the economic benefits of project development and to build capacity in the people and businesses of Nigeria. The Agbami team embraced Nigerian Content as a strategic objective for project success, rather than as a government-imposed mandate. Agbami benchmarked the Nigerian Content of predecessor projects and established a Nigerian Content plan approximately 50% higher than previous accomplishments. These requirements were part of the project contracts, and all contractors understood the importance of delivering this objective. As a result, five modules for the FPSO were fabricated in Warri and Lagos, including the largest FPSO module (weighing more than 1,700 tons) built to date in Nigeria. For the first time in Nigeria, the stainless-steel-clad sub-sea manifolds were fabricated in Port Harcourt. In addition, the offloading buoy and mooring piles were fabricated in Lagos. Significant investment and capacity building occurred across the Nigerian yards to fabricate these facilities. In all, the Nigerian Content exceeded 10,000 tons of fabrication, employing more than 4 million man-hours with zero days-away-from work (DAFW) injuries. The goal was aggressive and led to challenges along the way, but it was successful because it was a reasonable plan that had the support of all partners.

Kitina Case: Mature-Field Rejuvenation with Long-Reach Wells and Massive Hydraulic Fracturing

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19455, "Mature Offshore Field Rejuvenation via Long-Reach Wells and Massive Hydraulic Fracturing: The Kitina Case History," by F. Okassa, SPE, L. Tealdi, D. Baldini, A. Casero, H. Malonga, D. Isella, A. Baioni, L. Riccobon, G. Obondoko, F. Itoua Konga, F. Pounga, and M. Rampoldi, SPE, Eni Congo, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed. Many West Africa offshore fields are maturing, and operators are completing secondary targets to maintain economical operation. However, the level of capital expenditure for interventions is critical. In the Kitina field, offshore Pointe Noire, Congo, deeper sands have been produced to economic depletion and reservoir studies indicated alternative production intervals. Reservoir modeling; operation geology; and drilling, completion, and production challenges encountered in the 2007 Kitina rejuvenation campaign are described. Introduction The Kitina field, discovered in 1991, has five reservoirs.3A—limestone and sandstone with silty clay2A—limestone: oolitic grainstone/packstone, bioclastic with good intergranular porosity and intercalation of sandstone with carbonate cement2A—south accumulation: oolitic grainstone/packstone, bioclastic with good intergranular porosity and intercalation of sandstone with carbonate cement1A—sandstone with carbonate cement and limestone1B—sandstone with carbonate cement and limestone Three reservoirs (2A, 1A, and 1B) were depleted with a peripheral water-injection scheme and crestal gas injection. The initial production rate of the field was approximately 50,000 BOPD (1997), declining over a 10-year period to 7,000 BOPD. As the field depleted, some wells were put on artificial lift, initially with electrical submersible pumps and currently with gas lift. The recovery factors have been estimated at 15% for Reservoir 1B and between 25 and 30% for Reservoirs 1A and 2A. To initiate rejuvenation of the fields, it was decided to perform a full review of field potentials, which led to the following decisions.Optimize the recovery from Reservoir 3A (previously considered as marginal because of low permeability and the low production rates of the three wells already completed) by use of a massive hydraulic-fracturing campaign.Drill a long-reach and ultradeep well (KTM-SM5) in the south field structure into the Reservoir-2A south accumulation. Reservoir 3A Potential production from Reservoir 3A was studied by correlating with a similar sequence in another field, the Sounda marine field, 8 km east of Kitina. The formation permeability to oil ranges from 2 to 7 md. Three wells have been completed in this reservoir. Each well was produced as natural flow, but was completed with gas lift mandrels to accelerate well cleanup. Reservoir-3A production potential, from those three wells, was approximately 800 BOPD.

中東アブダビ海域炭酸塩岩油層におけるガス圧入パイロットテスト

Japan Oil Development Company (JODCO) participates in the development of several oil fields in the offshore oil field in Abu Dhabi, through Joint Venture with Abu Dhabi National Oil Company (ADNOC) and other Shareholders.The subject “A” oil field has carbonate reservoirs, 40 km×30 km closure and has started production since 1967. Peripheral water injection and crestal gas injection have been applied for pressure maintenance since 1972 and 2005 respectively.Further development studies are ongoing for an increase in recovery and overcoming further pressure decline. Down flank gas injection is considered as one of the most attractive schemes. Therefore, gas injection pilot test has commenced to evaluate the effectiveness of full field down flank gas injection in “A” oil field since 2001.10 dedicated wells (6 gas injectors, 2 producers and 2 observers) have been drilled in sublayers A, B and C. Line drive gas injection scheme is being tested in sublayers A and B. Five spot gas injection scheme is being tested in sublayer C. Currently long term gas injection test and extensive reservoir surveillance are ongoing. The main criteria for success of the pilot are sweep efficiency (vertical, lateral and microscopic), miscibility, residual oil saturation to gas (Sorg) and impact on the aged facilities.This report introduces the summary of the pilot test and its reservoir performance to date.

Maximizing Production Capacity With Intelligent-Well Systems in a Deepwater West Africa Field

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 103308, "Maximizing Production Capacity Using Intelligent- Well Systems in a Deepwater, West Africa Field," by D.J. Goggin, M.A. Ovuede, N. Liu, SPE, U. Ozdogan, SPE, P.B. Coleman, SPE, and D.P. Meinert, SPE, Chevron; I. Nygard, Statoil; and J. Gontijo, Petroleo Brasileiro Nigeria, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. Large, deepwater fields with a limited number of wells may require intelligent-well systems to maximize production capacity under facility constraints. Agbami field, a highly dipping reservoir with many producing zones and few wells, will use intelligent-well systems consisting of interval-control valves (ICVs) and many sensors to monitor, analyze, and control (MAC) injection and production at the zonal level. Introduction A key objective for optimizing asset performance is maximizing and accelerating recovery by producing wells at optimal rates, which will delay the arrival of water and gas while honoring the mechanical limitations of the production network (e.g., flowlines, manifolds, risers, and separators). The challenge for operators is to know where the excess production capacity exists in the network at any given time and what control settings can be adopted if well failures occur. Therefore, a MAC process is used to respond to unplanned operational interruptions and to be prepared for longer-term reservoir behavior caused by geologic uncertainties. Reservoir Description The overall field structure is a northwest/southeast-trending four-way-closure anticline on the Niger delta front, approximately 65 miles offshore Nigeria in the Gulf of Guinea. The anticlinal structure has dip angles as steep as 30° on the northeast and southwest flanks. From 3D-seismic data, several faults have been mapped across the anticlinal structure. A major thrust fault divides the Agbami field into inboard (northeast) and outboard (southwest) halves. Normal faults further subdivide the field into eight potentially noncommunicating areas. The high structural dip and the fault compartments are important factors in the well-placement strategy, injection patterns, and oil-recovery expectation. The field has four stacked reservoirs with distinct pressure profiles. The current geologic model includes three of these reservoirs designated as 14MY, 16MY, and 17MY. The 17MY reservoir contains 80% of the total-field oil-in-place of approximately 2 billion bbl. Field-Development Plan and Production Network The field-development plan recommends midflank oil production with crestal gas injection and peripheral water injection as the primary oil-recovery, pressure-maintenance, and gas-disposition scheme in the 17MY units. Oil properties of 47°API gravity and 0.23-cp viscosity are favorable to a combined crestal miscible-gas drive and peripheral water-injection scheme in a highly dipping reservoir. Thirty-eight wells are planned in three drilling stages. Plans include 17 Stage-1 wells drilled and completed before first oil production, comprising 10 producers, four water injectors, and three gas injectors. Stages-2/-3 drilling occurs after first oil production.

Modelización de procesos de combustión segregada in-situ mediante un modelo de desplazamiento vertical aplicado a un campo Colombiano.

Recently it has been proposed the incorporation of horizontal well technologies in thermal EOR processes like the in situ combustion process (ISC). This has taken to the conception of new recovery mechanisms named here as Segregated In-Situ Combustion processes which are conventional in-situ combustion process with a segregated flow component. Top/Down combustion, Combustion Override Splitproduction Horizontal-well and Toe-to-Heel Air Injection are three of these processes, which incorporate horizontal producers and gravity drainage phenomena. When applied to thick reservoirs a process of this nature could be reasonably modeled under concepts of conventional In-Situ Combustion and Crestal Gas Injection, especially for heavy oils mobile at reservoir conditions. A process of this nature has been studied through an analytic model conceived for the particular conditions of the Castilla Field, a homogeneous thick anticline structure containing high mobility heavy oil which seems to be an excellent candidate for the application of these technologies.

Three-dimensional visualization for well placement and geosteering: Njord Field, offshore mid-Norway

Njord is a structurally complex Lower Jurassic oil field located on the Halten Terrace, offshore mid-Norway. The field was discovered in 1986 and has been under production since 1997. The field is produced by a combination of depletion and crestal gas injection. Difficulties in finding new economically viable drilling targets led to a drilling stop in 2001–2002 and production is now in decline. A second drilling phase comprising three infill wells began in late 2002. Production results from these three wells will be critical for determining Njord’s future beyond 2005. During the drilling stop, advanced 3D visualization techniques were used to unravel the field’s complex extensional fault pattern. New well targets were identified using multiple seismic datasets and multiple interpretations. 3D visualization was also used during drilling to keep the wells within the reservoir and to avoid an unstable formation. Reservoir simulation models were used to identify areas with undrained potential, and 4D seismic data indicated fault blocks where changes in gas saturation had occurred. The reservoir oil is initially under-saturated, but gas has also come out of solution in areas with significant pressure depletion. Gas has also been re-injected. New wells were planned to avoid these fault blocks. Target points were placed using 3D visualization software and well path dog-leg angles were calculated. The process continued iteratively until a well path had been achieved with maximum reservoir penetration and realistic dog-leg angles (< 3.5°). Real time data were transmitted to shore during drilling using a web service. These data included survey, petrophysical log, biostratigraphical and borehole image data that were used alongside the 3D visualizations. In this way, drilling progress through the G&G interpretation was continuously monitored. Similarly, geosteering, or plug back and sidetrack, decisions were quickly evaluated. Supplementary material: Movies referred to in the article are available at https://doi.org/10.6084/m9.figshare.c.4812936

Gravity Drainage-Lab Tests, Relative Permeability Calculation, and Field Simulation

Abstract In order to confirm the expected high recoveries obtained in gravity drainage field operations we performed a series of lab tests, developed an oil relative permeability calculation, and used this data to conduct a reservoir simulation for a Brazilian offshore oil field. The lab tests were conducted at ambient temperature and low pressure, and were performed in long cores (90 - 252 cm long) with dead oil and conventional production where the oil was produced at the lower end of the vertically oriented core and air entered the upper end. For one test we performed a counter-current drainage test using live oil where the production was collected at the lower end of the core and the liberated dissolved gas was removed counter-currently from the upper end. The saturation evolution inside the core was monitored by an X-Ray system. Using the same rock and fluids, centrifuge tests were performed using 3 - 4 cm long plugs to compare to the core displacement test results. When the results did not agree, an explanation for the variance using a model of bundles of capillary tubes was postulated. Verification using the principle of minimum energy was performed. A computer program was implemented to calculate the oil relative permeability using the lab data, the results of which were compared with the published literature. The calculated relative permeability was used to simulate the behaviour of a Brazilian offshore oil field that was initially exploited with water injection, and then, due to the appearance of a secondary gas cap, subsequently subjected to gas injection into the crest of the structure. Introduction Numerous papers describe lab test results concerning gravity drainage(2–4, 7, 8, 10, 12, 14, 16, 19, 23, 24, 26, 27). We present the results of gravity drainage long core tests and centrifuge tests using samples with identical rock and fluid properties. In those situations where the results of the two methods did not agree, we calculated the results by considering a bundle of capillary tubes to understand the difference. The long core tests showed, in accordance with the literature, a very low residual oil saturation at the top of the core. The results of these tests were used to calculate the oil relative permeability to be used in to simulate the performance of an offshore Brazilian oil field with a 110.6 MMSTm3 OOIP has been under production for 13 years under peripheral water injection and, due to the appearance of a secondary gas cap, has been supplemented with a crestal gas injection. After a history match, we performed the production forecast for both water and combined water and gas injection. Methodology of the Experimental Tests Long Core Tests After the traditional core mounting process, the sequence of the tests can be summarized in the following steps:Measurement of rock and fluid properties;Water saturation of the sample under vacuum;Displacing the water by oil and establishing the initial water saturation; and,Drainage of oil in the presence of air.

Production and geologic implications of the Natih 9-C, 3-D seismic survey

In the northern part of the Sultanate of Oman, oil is produced chiefly from carbonate reservoirs of Cretaceous age. Major fields such as Fahud and Natih (Figure 1) were discovered in the 1960s and rapidly brought on stream by Petroleum Development Oman (PDO). The oil-bearing reservoirs occur in the Natih and the Shu'aiba carbonate formations (Figure 2). The main reservoir in both fields is the Natih Formation. Natih Field was brought on stream in 1967 and, like Fahud Field, production was initially by a depletion drive. As a result of falling reservoir pressure, water injection was installed and this was later supplemented by gas injection. When the petroleum engineers of PDO recognized the importance of fractures to development of these fields, the developments were changed to gas/oil gravity drainage (GOGD). The full-field GOGD involves lowering the fracture oil rim by 70 m through crestal gas injection and down-dip water production.