Attic Oil Research Articles

Co-Injection of Foam and Particles: An Approach for Bottom Water Control in Fractured-Vuggy Reservoirs

Fractured-vuggy carbonate reservoirs are tectonically complex; their reservoirs are dominated by holes and fractures, which are extremely nonhomogeneous and are difficultly exploited. Conventional water injection can lead to water flooding, and the recovery effect is poor. This paper takes the injection of foam and solid particles to control bottom water as the research direction. Firstly, the rheological properties of foam were studied under different foam qualities and the presence of particles. The ability of foam to carry particles was tested. By designing a microcosmic model of a fractured-vuggy reservoir, we investigated the remaining oil types and the distribution caused by bottom water. Additionally, we analyzed the mechanisms of remaining oil mobilization and bottom water plugging during foam flooding and foam–particle co-injection. The experimental results showed that foam was a typical power-law fluid. Foam with a quality of 80% had good stability and apparent viscosity. During foam flooding, foam floated at the top of the dissolution cavities, effectively driving attic oil. Additionally, the gas cap is released when the foam collapses, which can provide pressure energy to supplement the energy of the reservoir. Collaborative injection of foam and solid particles into the reservoir possessed several advantages. On one hand, it inherited the benefits of foam flooding. On the other hand, the foam transported particles deep into the reservoir. Under the influence of gravity, particles settled and accumulated in the fractures or cavities, forming bridge plugs at the connection points, effectively controlling bottom water channeling. The co-injection of foam and solid particles holds significant potential for applications.

Evaluation and improvement of CO2 assisted gravity drainage for enhanced oil production in China

In view of the diversity of petroleum reservoir types, most petroleum reservoirs have very strong heterogeneity in properties. For many water flooding reservoirs, with the continuous water injection process, the effect of enhancing oil recovery begins to deteriorate gradually, and a large amount of remaining oil mainly remains at the top of the reservoir formation, becoming as "attic oil". Under the "double carbon" target, in order to cope with the high demand for oil consumption in China, a new oil exploitation technology, CO2 assisted gravity drainage is explored in this study. Taking four cores with similar porosity and permeability as research objects, laboratory displacement experiments were carried out to verify the effectiveness of CO2 assisted gravity drainage in enhancing oil recovery through different CO2 injection methods and injection rates. Moreover, through the comparison of gas flooding recovery factors under different gas injection rates, it is found that the stable control of gas-oil interface is the key to the successful implementation of CO2 assisted gravity drainage. After that, based on references and numerical simulation, this paper analyzes the technical key points of the successful implementation of this technology, proposes the method of introducing "surfactant + CO2" composite system to regulate the stability of gas-oil interface, and clearly points out the issues to be focused in future researches. The study can provide a useful reference for the field implementation of CO2 assisted gravity drainage, and then promote effective carbon utilization and oil production.

Immiscible Viscous Fingering at the Field Scale: Numerical Simulation of the Captain Polymer Flood

Summary Immiscible fingering in reservoirs results from the displacement of a resident high-viscosity oil by a significantly less viscous immiscible fluid, usually water. During oil recovery processes, where water is often injected for sweep improvement and pressure support, the viscosity ratio between oil and water (μo/μw) can lead to poor oil recovery due to the formation of immiscible viscous fingers resulting in oil bypassing. Polymer flooding, where the injection water is viscosified by the addition of high-molecular-weight polymers, is designed to reduce the impact of viscous fingering by reducing the μ0/μw ratio. A considerable effort has been made in the past decade to improve the mechanistic understanding of polymer flooding as well as in developing the numerical simulation methodologies required to model it reliably. Two key developments have been (i) the understanding of the viscous crossflow mechanism by which polymer flooding operates in the displacement of viscous oil and (ii) the simulation methodology put forward by Sorbie et al. (2020), whereby immiscible fingering and viscous crossflow can be simply matched in conventional reservoir simulators. This publication extends the work of Beteta et al. (2022b) to conceptual models of a field case currently undergoing polymer flooding—the Captain field in the North Sea. The simulation methodology is essentially “upscaled” in a straightforward manner using some simple scaling assumptions. The effects of polymer viscosity and slug size are considered in a range of both 2D and 3D models designed to elucidate the role of polymer in systems both with and without “water slumping.” Slumping is governed by the density contrast between oil and water, the vertical communication of the reservoir and the fluid velocity, and, when it occurs, the injection of water channels along the bottom of the reservoir directly to the production well(s). It is shown that polymer flooding is very applicable to a wide range of reservoirs, with only modest injection viscosities and bank sizes returning significant volumes of incremental oil. Indeed, oil incremental recoveries (IRs) of between 29% and 89% are predicted in the simulations of the various 2D and 3D cases, depending on the slug design for both nonslumping and slumping cases. When strong water slumping is present, the performance of the polymer flood is significantly more sensitive to slug design, as alongside the viscous crossflow mechanism of recovery, a further role of the polymer is introduced—sweep of the “attic” oil by the viscous polymer flood, which is able to overcome the gravity-driven slumping, and we also identify this mechanism as a slightly different form of viscous crossflow. In slumping systems, it is critical to avoid disrupting the polymer bank before sweeping of the attic oil has been performed. However, as with the nonslumping system, modest injection viscosities and bank sizes still have a very significant impact on recovery. The conceptual models used here have been found to be qualitatively very similar to real field results. Our simulations indicate that there are few cases of viscous oil recovery where polymer flooding would not be of benefit.

A Comparison of The Performances of Conventional and Low Salinity Water Alternating Gas Injection for Displacement of Oil

This study focuses on identifying the crucial physical and chemical factors, such as gravity, initial oil phase, injection depth, vertical to horizontal permeability contrast, and salinity of injected water for improving oil recovery factor during water alternating gas (WAG) injection. The conventional WAG injection attracts interest from oil and gas industry and hence, has become one of the most reliable enhanced oil recoveries (EOR) techniques. During WAG injection, due to gravity effect, water subsides below oil layer while gas overflow above the oil layer. In fact, water sweeps bottom zones of the reservoir and gas sweep the attic oil at the upper zones of the reservoir. Although the conventional WAG does improve oil recovery factor, there still remains a substantial amount of oil in reservoir pores due to rock-fluid and fluid-fluid interfacial tensions (IFT) that leads to the capillary forces impeding the microscopic displacement efficiency. The low salinity waterflooding (LSWF) was therefore proposed to break the IFT between rock clay and fluids, and further increase oil recovery factor. Recent researches revealed that LSWF alters oil-wet reservoir to water-wet behavior. This wettability alteration is believed to be the main mechanism of LSWF to improve oil recovery. Other mechanisms of LSWF include multi-ion exchange (MIE) between rock clay minerals and injected salt water, pH increase, and fines migration. In this study, the CMG GEM simulator was used to simulate conventional WAG injection and LSWAG injection. The simulation results showed that there is an increase of oil recovery factor of about 6% for WAG injection with low salinity water of 1027ppm to sea water of 51,346 ppm. The simulations have also showed that the physical factors namely, gravity, initial oil phase, injection depth, vertical to horizontal permeability contrast are influential on the displacement efficiency and must be studied thoroughly in the design of LSWAG operations besides the salinity and chemical composition of the injection water.

Mechanisms of remaining oil formation by water flooding and enhanced oil recovery by reversing water injection in fractured-vuggy reservoirs

To get a deeper understanding on the formation mechanisms and distribution laws of remaining oil during water flooding, and enhanced oil recovery (EOR) mechanisms by reversing water injection after water flooding, 3D visualization models of fractured-vuggy reservoir were constructed based on the elements and configuration of fractures and vugs, and typical fracture-vug structures by using advanced CT scanning and 3D printing technologies. Then, water flooding and reversing water injection experiments were conducted. The formation mechanisms of remaining oil during water flooding include inadequate injection-production well control, gravity difference between oil and water, interference between different flow channels, isolation by low connectivity channel, weak hydrodynamic force at the far end. Under the above effects, 7 kinds of remaining oil may come about, imperfect well-control oil, blind side oil, attic oil at the reservoir top, by-pass residual oil under gravity, by-pass residual oil in secondary channel, isolated oil in low connectivity channel, and remaining oil at far and weakly connected end. Some remaining oil can be recovered by reversing water injection after water flooding, but its EOR is related to the remaining oil type, fracture-cavity structure and reversing injection-production structure. Five of the above seven kinds of remaining oil can be produced by six EOR mechanisms of reversing water injection: gravity displacement, opening new flow channel, rising the outflow point, hydrodynamic force enhancement, vertically equilibrium displacement, and synergistic effect of hydrodynamic force and gravity.

Residual Oil Distribution Pattern in a Fault-Solution Carbonate Reservoir and Countermeasures to Improve Oil Development Effectiveness

Because of the strong random distribution of fractures and caves, fault-solution carbonate reservoirs exhibit significantly different flow mechanisms and development methods from conventional carbonate reservoirs. Natural elastic and edge-bottom water flooding are the main processes for developing fault-solution reservoirs. The rapid decline in production and the complex residual oil distribution are major challenges for oil production. This study is aimed at (1) assessing the residual oil migration law, (2) determining the residual oil distribution characteristics, and (3) identifying the main controlling factors using numerical simulation, to provide suggestions for enhancing oil recovery. The results showed that fractures are the main channel for oil flow and the main path of bottom water coning in the fault-solution reservoirs. The channeling of bottom water along high-angle fractures is the main reason for the decline in oil production. In addition, bottom water coning and gas/water injection are the key factors affecting the distribution of residual oil, while the irregular development of fractures and caves is the main factor causing diversified distribution patterns of the residual oil. The residual oil distribution patterns of fault-solution reservoirs include 4 types, namely, attic, bottom water rising and blocking, separated fracture-cavity, and pores near high-conductivity channel types. For tapping the potential of residual oil, several approaches can be used, namely, deploying new wells or using sidetracking of old wells in the loft and the separated fracture-cavity reservoirs. In addition, the attic residual oil type can also be developed using drainage oil recovery or gas injection for oil replacement. Liquid lift pump, water shutoff, and water cone restrain can also be used to tap residual oil from rising bottom water. Optimizing profile control and water shutoff measures and adjusting the injection and production relationship can be effective approaches for developing residual oil in the pores and cracks beside the high diversion channel.

Experimental research on the mechanisms of improving water flooding in fractured-vuggy reservoirs

Fractured-vuggy reservoirs have extremely complex reservoir characteristics, leading to a large amount of remaining oil not being recovered after water flooding. In order to solve the problem of the low recovery in fractured-vuggy reservoirs, we utilized 3D printing technology to fabricate two-dimensional and three-dimensional experimental models based on the typical reservoir structure. A series of experiments with different models on improving water flooding is conducted to study the production improvement effect. The difference in oil-water distribution or oil saturation distribution before and after improved water flooding is also compared, and the mechanism is analyzed. The results show that the oil-water gravity differentiation is the most critical factor affecting the remaining oil distribution, and changing the injected pressure or its propagation direction is the root of improving water injection. Reversing injection-production wells, increasing injection strength, water plugging, and cyclic water injection can effectively increase the sweeping scope or displacement efficiency. The attic oil, residual oil in filling medium, bypass remaining oil, and water cone remaining oil can be produced by one or more improving water flooding methods. This paper provides effective measures and mechanisms for the efficient and rapid development of fractured-vuggy reservoirs.

Study Examines Incremental Method vs. Split Conditions in Reserves Booking

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206104, “Incremental Method vs. Split Conditions: Discussing the Similarities Between Reserves Evaluation and a Madoff Scheme,” by Dominique Salacz, SPE, and Farid Allam, SPE, ADNOC, and Imre Szilagyi, Eötvös Loránd University, et al., prepared for the 2021 SPE Annual Technical Conference and Exhibition, Dubai, 21–23 September. The paper has not been peer reviewed. After the oil-price crashes of 2014 and 2020, several merger and acquisition deals ended in litigation because operators canceled major projects or infills wells that were booked in “probable” reserves only. In the complete paper, the authors challenge the compatibility between the deterministic incremental reserve assessment method and the concept of split condition, which is not allowed for reserves booking under the Petroleum Resources Management System (PRMS). With some examples, the authors argue that the incremental method may mislead investors if used wrongly. The Two Approaches PRMS is a simple, fit-for-purpose system. However, it still allows for reporting volumes under slightly different methods that may lead to very different results based on the definition adopted for the “project” by the evaluator. The text of the PRMS is quoted extensively in the complete paper in defining these methods. The authors write that the deterministic incremental method seems to be favored by evaluators educated under, or heavily exposed to, pre-2010 US Securities and Exchange Commission regulations, in which proved reserves were only disclosed. Under this approach, the term “proven” generally refers to recoverable volumes expected from the partition of the reservoir with a high degree of confidence related to the high level of geological knowledge. The authors also write that the deterministic scenario method, on the other hand, evidently is favored by evaluators and engineers with less exposure to the pre-2010 guidelines. This method provides three estimates (low, best, and high) for every individual project. Comparing the Two Methods The study-case accumulation is defined by a simple structural trap controlled by a top seal and a fault on the western side of the asset (Fig. 2 of the complete paper). Oil has been discovered by Well W1, which hit the permeable top at 9,695 ft near the structure’s crest. For mechanical reasons, drilling operations were stopped and the lowest known hydrocarbon sets the oil down to (ODT) at 9,785 ft, providing a discovered oil column of 90 ft. Horizontal Well WH2 was drilled into the discovered reservoir partition. Today, Well WH2 is the only producing well of the accumulation. Well W1 will be reperforated during a workover to produce the attic oil of the reservoir. Because the well did not reach the aquifer, a major uncertainty for further development is assigned to oil/water contact (OWC) position. At the current stage of resource maturation, up to 11 additional wells are considered.

Effect of rubber particles on water flow behavior in fractured-vuggy reservoirs

The presence of the large channel in fractured-vuggy reservoirs diminishes the sweep efficiency of any water, gas or polymer flooding. This paper presents a novel type of rubber particle for water shutoff agent and the flow direction of water is adjusted by plugging the large channel. Simultaneously, through the microscopic displacement experiment of the organic glass etching model, the water flow behavior and injection parameters optimization are studied. The results show that the resistance of solid media to fluid flow is almost zero when the oil-water two-phase flow occurs, and the gravity action is prominent. Therefore, there are still a lot of residual oil of karst cave, flow around oil and attic oil with poor connectivity after the fractured-vuggy reservoir is displaced by injected water. In addition, the rubber particles can form a temporary plugging zone by migration – accumulation – bridging under formation conditions, resulting in the flow direction of subsequent injection water changes from the large channel to the small channel, thereby reducing water content and increasing oil production. By optimizing the injection parameters of rubber particles, the optimal injection volume, particle size and injection speed are obtained, which are 0.02PV, 0–1 mm, 2–4 mm and 25 mL/min, respectively.

Laboratory study of nitrogen/foam enhanced oil recovery from vuggy-fractured carbonate reservoirs

Aiming at a special vuggy-fractured carbonate, the mechanism of nitrogen flooding, co-injection of water and nitrogen (CWN), water alternating gas injection (WAG) and foam flooding was studied by slate model. Experimental results showed that mechanism of nitrogen flooding was displacing attic oil, which was similar to other vuggy fractured reservoirs. While to CWN, the main mechanism was not relieve of gas channeling. It was found that gas mainly flowed through the upper hole or the upper location of hole and water mainly flowed along the lower hole or the lower location of hole. The main reason why CWN recovery was higher than nitrogen flooding was that during nitrogen flooding, nitrogen would substitute attic oil, so some oil would flow to the water channel and form remaining oil in water channel. During CWN, water flowed mainly along the water channel in previous water flooding, so remaining oil in water channel would not occur during CWN. While to WAG, it had lowest recovery. Among the previous three flooding methods, remaining oil named “sandwich oil” was found between gas and water.

A Novel Assisted Gas–Oil Countercurrent EOR Technique for Attic Oil in Fault-Block Reservoirs

As the mature oil fields have stepped into the high water cut stage, the remaining oil is considered as potential reserves, especially the attic oil in the inclined fault-block reservoirs. A novel assisted gas–oil countercurrent technique utilizing gas oil countercurrent (GOC) and water flooding assistance (WFA) is proposed in this study to enhance the remaining oil recovery in sealed fault-block reservoirs. WFA is applied in our model to accelerate the countercurrent process and inhibit the gas channeling during the production process. Four comparative experiments are conducted to illustrate enhanced oil recovery (EOR) mechanisms and compare the production efficiency of assisted GOC under different assistance conditions. The results show that WFA has different functions at different stages of the development process. In the gas injection process, WFA forces the injected gas to migrate upward and shortens the shut-in time by approximately 50% and the production efficiency improves accordingly. Compared with the basic GOC process, the attic oil swept area is extended 60% at the same shut-in time condition and secondary gas cap forms under the influence of WFA. At the production stage, the WFA and secondary gas cap expansion form the bi-directional flooding. The bi-directional flooding also displaces the bypassed oil and replaced attic oil located below the production well, which cannot be swept by the gas cap expansion. WFA inhibits the gas channeling effectively and increases the sweep factor by 26.14% in the production stage. The oil production increases nearly nine times compared with the basic GOC production process. The proposed technique is significant for the development of attic oil in the mature oil field at the high water cut stage.

Horizontal Infill Well With AICDs Improves Production in Mature Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195450, “Horizontal Infill Well With AICDs Improves Production in Mature Field: A Case Study,” by Ilhami Giden, SPE, and Michael Nirtl, SPE, OMV Austria; Hans Thomas Maier, SPE, University of Leoben; and Ismarullizam Mohd Ismail, SPE, Tendeka, prepared for the 2019 SPE Europec featured at the 81st EAGE Annual Conference and Exhibition, London, 3–6 June. The paper has not been peer reviewed. This paper compares the performance of three mature-field horizontal infill wells, one of which is completed with autonomous inflow-control devices (AICDs). Two of the horizontal infill wells are targeting attic oil in an area with low risk of gas production; one of these two wells is completed with slotted liners and the other with AICDs. The third horizontal well was placed in an area with higher gas saturation. The AICDs were found to choke back a high amount of fluid and keep the water cut at a stable plateau•level. Field Introduction Matzen is a supermature oil field northeast of Vienna and is one of the largest onshore oil fields in Europe. The field consists of several stacked reservoirs, of which the 16th Tortonian horizon (16.TH) is the largest. The westernmost part of the 16.TH is called the Bockfliess area. In this area, 77 wells are currently active: 62 are production wells and 15 are injection wells. During 2011 to 2015, the last major field-redevelopment project in the area, with the objective of doubling the gross production rate, was executed. One goal of the project included a conversion from low-rate sucker rod pumps (SRPs) to high-rate electrical submersible pumps (ESPs). Horizontal infill wells were also drilled to optimize the ultimate recovery in the reservoir. The 16.TH sandstone reservoir lies between –1490 and –1455 m TVDss [total vertical depth subsea (i.e., total vertical depth minus the elevation above mean sea level of the depth reference point of the well)], with excellent permeability and an average porosity of 27%. Reservoir temperature•is 60°C and current reservoir pressure is 120 bar. Oil gravity is 25•°API, while oil viscosity is 5•cp. Average water cut exceeds 97%. AICD Technology In recent years, several different types of AICDs have been designed. The most common device types are fluidic-diode, electrical-resistivity, and rate-controlled-production (RCP). This paper covers the RCP type. The working principle of RCP AICDs differs from type to type. The Levitating-Disc AICD. The AICD that is installed in Well BO 208 is an improved version of the RCP. The design works on the principle of a levitating disc. The AICD valve restricts the flow rate of low-viscosity fluids. When gas or water flows through the AICD valve at the same drawdown, the velocity of the water and gas will increase, reducing the dynamic pressure and levitating the disc toward the inlet to choke the flow. The AICD valve is assembled as part of the sand-screen joint. The reservoir fluids enter the completion through the sand-screen filter and flow into the in-flow-control housing where the AICD is mounted. The fluids then flow into the production stream to the surface together with the production from the rest of the screens.

Foam-EOR method in fractured-vuggy carbonate reservoirs: Mechanism analysis and injection parameter study

Fractured vuggy carbonate reservoirs in the Tahe Oilfield, China, have many diverse and unevenly distributed reservoir spaces. These spaces mainly consist of corrosion pores, high-density fractures, and large vugs. Reservoir development began with natural energy and pressure maintenance methods. However, a rapid rise of the water cut always led to poor oil production. Gas enhanced oil recovery (EOR) has shown notable improvement in the Tahe Oilfield; however, the recovery efficiency was limited by gas channeling. In this paper, a two-dimensional (2D) physical model was developed for a more detailed visual of the flow characteristics and the effect of the injection parameters (i.e., the injection rate, the injection slug size, the injection timing and the injection position) were evaluated. Water flooding can produce a certain amount of oil; however, the remaining oil types are the same as those found during the bottom water invasion period, that is, attic oil, bypass oil, and oil films. A better approach is N2 flooding, which can replace the attic oil at the top of the vug by gravitational differentiation. An even better method is N2 foam flooding. When the injection volume of N2 foam reached a certain level, foams accumulated in the flow channels, decreased fluid mobility, inhibited the gas channeling, and expanded sweep efficiency. Moreover, the N2 foam had excellent effects on oil film stripping, crude oil emulsification, and carrying oil droplets, thereby improving the microscopic displacement efficiency. In addition, the results of injection parameter effect can help researchers and reservoir engineers better understand and implement the foam-EOR method in the fractured vuggy carbonate reservoirs.

A Reversed Geo–Dynamic Approach for Brownfield Rejuvenation

Summary Brownfields in this paper are defined as mature fields where production declined to less than 35–40% of the plateau rate and where primary and secondary reserves have been largely depleted. Big data, high field complexity after a long production history, and slim economic margins are typical brownfield challenges. In the exploration-and-production (E&P) industry, “sequential” field-evaluation approaches (first “static,” then “dynamic”), have proved successful for greenfield development, but often do not achieve satisfying results for brownfields. This paper presents a new work flow for brownfield re-evaluation and rejuvenation. The “reversed” geo-dynamic field modeling (GDFM) rearranges existing elements of reservoir evaluation to obtain a purpose-driven, deterministic reservoir model, which can be quickly translated into development scenarios. The GDFM work flow is novel because (1) it turns upside down the discipline-driven sequential work flow (i.e., starts with the history match) and (2) it uses dynamic data as input to calibrate seismic (re-) interpretation that acts as a main integration step. It combines all available data already during horizon and fault mapping. Field diagnosis, flow-unit identification, well-test reanalysis, and petrophysical and geological interpretations are all combined in a cross-discipline interaction to guarantee data consistency. This directly ensures a fully integrated, “geo-dynamic” model that forms the basis for reservoir modeling. The full dynamic/static data coupling at an early stage is the main strength of the GDFM. It reduces the model complexity, and narrows the uncertainties. Project-execution time is considerably shortened by avoidance of the characteristic full-cycle loop iterations of the sequential approaches. A brownfield example illustrates the benefits of GDFM: a consistent history match with high model accuracy and confidence. In the field example, the GDFM work flow has facilitated a turnover at only 70% of the original time budget. The ongoing drilling has confirmed model validity (“attic oil” predictions), thus further postponing the economic limit of the brownfield.

Experimental investigation on continuous N 2 injection to improve light oil recovery in multi-wells fractured-cavity unit

Abstract The purpose of this experimental study is to evaluate the feasibility and oil recovery efficiency of continuous N 2 injection in a multi-well fractured-cavity reservoir. In this study, the similar criterion of physical simulation was firstly discussed. In order to reveal the mechanism of remaining oil startup and production performance characteristic by continuous N 2 injection, a visualized two-dimensional fractured-cavity model and a three-dimensional pressure resistant model were designed and fabricated respectively based on the similar theory. And the 2D visualized physical experiments and 3D physical experiments were performed with the simulated oil and brine reservoir samples in Tahe oilfield. Four groups of experiments in 2D and 3D model were performed, each of which included bottom water depletion driving, water injection and N 2 injection. The 2D visualized experiments indicated the main mechanism of N 2 developing remaining oil was to occupy the high position and replace the attic oil due to gravitational differentiation. Furthermore, both the 2D and 3D experiments demonstrated that higher oil recovery factor could be achieved if N 2 was injected through high positional wells. The 3D physical model is closer to the real reservoir condition, so the production performance can reflect the real field production process. This paper confirmed the efficiency of continuous N 2 flooding in the light oil saturated fractured-cavity reservoir.

Integrated Asset Modeling: An Approach to Long-Term Production Planning

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 176322, “Samarang Integrated Operations: Integrated Asset Modeling— An Innovative Approach for Long-Term Production Planning Focused on Enhanced Oil Recovery,” by W. Sifuentes and J. Moreno, Schlumberger; P. Kumaran and R. Hamdan, Petronas; M. Muhamed Salim, M. Mohd. Som, H.W. Lee, A. Ahmad, N. Pangereyeva, S.S. Biniwale, N.J. Rodriguez, J.T. Nitura, R. Alia, O.A. Talabi, and V. Halabe, Schlumberger; and S. Pedraza, SPE, prepared for the 2015 SPE Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 20–22 October. The paper has not been peer reviewed. With declining trends in production and dwindling reserves for a 35-year-old offshore field, the Samarang Redevelopment Project was initiated with a vision toward implementing integrated operations as an asset-management decision-support tool. To realize expected reserves and optimize the production, an integrated-asset-model (IAM) concept is introduced with state-of-the-art modeling techniques to treat the asset as a whole unit rather than as isolated silos, which had been the traditional approach. Introduction The Samarang field is located in Subblock 6S-18 northwest of Labuan in eastern Baram Delta province. The production history of the field, first discovered and developed in the 1970s, is discussed in detail in the complete paper. A full-field review was carried out from 2004 to 2007 with the objective of identifying redevelopment opportunities. A field-development plan (FDP) was then established before an alliance was signed in 2010 to redevelop the field. The redevelopment team has drilled more than 17 infill wells, obtained new 3D- seismic data, carried out several studies including fine tuning of the enhanced-oil-recovery (EOR) development plan, and executed an extensive program of production enhancement and surveillance activities to boost the field production. This has given the team further insight into the Samarang field potential as well as the untapped near-field potential. The proposed EOR process is gas-assisted simultaneous water-and-gas (GASWAG) injection. This process consists of simultaneously injecting water updip in the gas cap and gas downdip in water-swept zones. The numerical reservoir-simulation model is the primary tool used for the EOR evaluations, optimizations, and forecasts. Implementation of the EOR scheme requires strategically positioning infill and injection wells. The recovery mechanisms targeted by this EOR scheme include Displacing attic oil back to existing well completions Sweeping the remaining oil toward new wells Repressuring the compartments Improving vertical sweep by using assistance gravity segregation Reducing residual oil in water by injecting gas in water-swept layers Traditionally, planning, forecasting, and optimization have been performed by the conventional approach of considering the reservoir, surface-network, and process-system models as being relatively isolated from one another. In this regard, many simplifications were taking place to translate the shared production limits, and account for surface backpressures, for each of the isolated models. These simplifications have negatively influenced production forecast for long-term predictions. The objective is to use an IAM approach to analyze and improve the production process for long-term planning.

Investigation on formation and distribution of remaining oil and sensitivity analysis in fracture-vuggy media

ABSTRACTDrilling and dewaxing are used to manufacture the quantitative model and stochastic model of fracture-vuggy media, respectively, which are used for the investigation on the oil displacement of full diameter cores. The formation and distribution of remaining oil and sensitivity analysis in fracture-vuggy media are studied. The research results show that the density difference between the displacing phase and the displaced phase and the connection position between fractures and vugs determine the fluid distribution law in the vugs. After water flooding, the remaining oil is composed of “attic oil,” “occlusion oil,” “corner oil,” “blind-vug oil,” “oil film,” and “dead oil region.” Then, the influences of oil viscosity, injection rate, density, and viscosity of driving fluid on oil recovery and remaining oil are studied.

Residual oil distribution characteristic of fractured-cavity carbonate reservoir after water flooding and enhanced oil recovery by N2 flooding of fractured-cavity carbonate reservoir

The 4th block Ordovician fractured-cavity carbonate reservoir of Tahe oil-field consists of high-density fractures and large caves which are well developed. The oil is stored in fractures and caves, rather than carbonate rock matrix. In other words, the carbonate rock matrix has no oil storage capability and permeability is extremely low. The fractured-cavity carbonate reservoir possesses the features of severe heterogeneity, complex structure of reservoir space. During the development, many shortcomings such as short period of stable production, early water breakthrough, fast increasing of water cut, high natural decline rate and low degree of development are exposed gradually. The well which cannot achieve effectiveness by water injection was selected to carry out N2 flooding experiments in Tahe oil-field. By the end of September 2012, the total injection volume of high pressure N2 was 700 m3 and the incremental oil production was 2600 t. However the displacement mechanism was still poorly understood. In this paper, a two-dimensional visual fractured-cavity carbonate reservoir model was developed based on the distribution feature, space structure and connection type of fractures and caves in reservoir space. Four main types of residual oil i.e., attic oil, locked oil, bypassed oil and residual oil trapped in the filled area were determined from the water flooding experiments. Also, their formation mechanism was investigated. In addition, the recovering mechanism of residual oil was clarified on the basis of N2 flooding experiments. The results show that N2 flooding can significantly increase the oil recovery by more than 40% after water flooding, and it mainly mobilized attic oil and partial locked oil. The entire experiment process was recorded by video, therefore the displacing process of residual oil can be observed directly. These results in this study indicate that N2 flooding has a broad application prospect in fractured-cavity carbonate reservoir.

Formation mechanism and distribution law of remaining oil in fracture-cavity reservoir

Abstract Drilling and dewaxing methods are used to create the quantitative model and stochastic model for fracture-cavity reservoirs respectively, which are used to investigate oil displacement in full diameter cores and to study the formation mechanism and distribution law of remaining oil in fracture-cavity reservoirs. The density difference between displacing phase and displaced phase and the connection position between fractures and cavities determine the fluid distribution in the cave. After the first water flooding, the remaining oil is composed of the following parts: the “attic oil” caused by the density difference between oil and water, the “occlusion oil” formed because the oil-to-water replacement is not instantaneous, the “corner oil” caused by the irregularity of the cave, the “blind cavity oil” formed because of the complex connection or low connectivity of the fracture-cavity system, and the “oil film” caused by the wettability of rocks. When the connection is higher, the amount of the “attic oil” is less. When the injecting velocity is lower and the viscosity of crude oil is lower, the amount of “occlusion oil” is less. The content of “corner oil” will become less when the cave figure is more regular, and the amount of corner is less. The amount of “blind cavity oil” is less when the connection is simple or the connectivity is high. In addition, on the water-wet rock surface, the content of “oil film” is less.

Lessons Learned From Energy Models: Iraq's South Rumaila Case Study

Summary Understanding reservoir behavior is the key to reservoir management. This study shows how energy modeling with rapid material-balance techniques, followed by numerical simulations with streamlines and finite-difference methods, aided understanding of reservoir-flow behavior. South Rumaila's long and elongated Zubair reservoir experiences uneven aquifer support from the western and eastern flanks. This uneven pressure support prompted injection in the weaker eastern flank to boost reservoir energy. We learned that aquifer influx provided nearly 95% of the reservoir's energy in its 50-year producing life, with water injection contributing less than 5% of the total energy supply. The west-to-east aquifer energy support is approximately 29:1, indicating the dominance of aquifer support in the west. Streamline simulations with a 663,000-cell model corroborated many of the findings learned during the material-balance phase of this study. Cursory adjustments to aquifer properties led to acceptable match with pulse-neutron capture or PNC-derived-time-lapse oil/water contact (OWC) surfaces. This global-matching approach speeded up the history-matching exercise in that performance of most wells was reproduced, without resorting to local adjustments of the cell properties. The history-matched model showed that the top layers contained the attic oil owing to lack of perforations. Lessons learned from this study include the idea that the material-balance work should precede any numerical flow-simulation study because it provides invaluable insights into reservoir-drive mechanisms and integrity of various input data, besides giving a rapid assessment of the reservoir's flow behavior. Credible material-balance work leaves very little room for adjustment of original hydrocarbons in place, which constitutes an excellent starting point for numerical models.