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One of the common challenges of applying foam for enhanced oil recovery is the foam instability in the presence of crude oil and nonwater-wet surfaces. In this experimental study, we systematically distinguish the effect of rock surface wettability from that of crude oil saturation on foam rheology under reservoir conditions. Neutral-wet Berea and reservoir sandstone cores are prepared by aging with crude oil, followed by the wettability index measurements. Transient foam generation and steady-state foam quality scans are conducted in neutral-wet cores, with/without water-flood residual oil. Nuclear magnetic resonance imaging is also utilized to measure the remaining oil saturation at the end of the foam-flood. It is shown that strong foam can be generated in a neutral-wet core with no residual oil because of the solubilization of the adsorbed crude oil components and the wettability alteration toward more water-wet conditions. However, in a neutral-wet core containing residual oil, foam generation is initially hindered. Foam generation occurs after injecting several pore volumes of surfactant solution and increasing the superficial velocity to overcome the minimum pressure gradient required for in situ foam generation. The findings from this study suggest that surface wettability in the presence of bulk oil saturation significantly affects transient foam generation. The final steady-state foam strength becomes comparable to the water-wet and oil-free case once the residual oil saturation is adequately reduced.

Summary This paper advances the understanding of foam transport in heterogeneous porous media for enhanced oil recovery (EOR). Specifically, we investigate the dependence of methane foam rheology on the rock permeability at the laboratory scale and then extend the observations to the field scale with foam modeling techniques and reservoir simulation tools. The oil recovery efficiency of conventional gasflooding, waterflooding, and water-alternating-gas (WAG) processes can be limited by constraints such as bypassing effects (including both viscous fingering and channeling mechanisms) and gravity override. The problem can be more severe if the reservoir is highly fractured or heterogeneously layered in the direction of flow. Foam offers the promise to address the three issues simultaneously by better controlling the mobility of injected fluids. However, limited literature data of foam-flooding experiments were reported using actual reservoir cores at harsh conditions. In this paper, a series of methane (CH4) foam-flooding experiments were conducted in three different actual cores from a proprietary reservoir at an elevated temperature. It is found that foam rheology is significantly correlated with the rock permeability. To quantify the mobility control offered by foam, we calculated the apparent viscosity on the basis of the measured pressure drop at steady state. Interestingly, the apparent viscosity was found to be selectively higher in the high-permeability cores compared with that in the low-permeability zones. We parameterized our system using a texture-implicit-local-equilibrium model (STARS™ simulator, Computer Modelling Group, Calgary, Alberta, Canada) to illustrate the dependence of foam parameters on rock permeability. In addition, we created a two-layered model reservoir using an in-house simulator called modular reservoir simulator (MoReS; Shell Research, Rijswijk, The Netherlands) to elucidate the role of different driving forces for fluid diversion at the field level. We took into consideration the combined effect of gravitational, viscous force, and capillary forces in our simulation. We show that the gravitational forces prevent the gas from sweeping the lower part of the reservoir. However, the poor sweep can be ameliorated by intermittent surfactant injection to generate foam. In addition, the capillary force which hinders the gas (nonwetting phase) from entering the low-permeability region can be effectively leveraged to redistribute the fluids in the porous media, resulting in better sweep efficiency. We conclude that foam if properly designed can effectively improve the conformance of the WAG EOR in the presence of reservoir heterogeneity.

Unquestionably, water breakthrough into the producing wells is one of the biggest threats to the development and production of oil and gas reservoirs around the world. The predicted water production profile from a numerical simulation model directly affects the estimated recoverable volumes and hence the decision making process for the field development and the facility design to handle the produced water. The problem of reliably predicting the water production profile exacerbates when dealing with thinly laminated sand reservoirs. Calculating the total water saturation (SW T ) using well log data in the hydrocarbon zone in this type of reservoirs is adversely affected by the convoluted readings of the conventional logging instruments whenever the resolution of the laminations goes beyond the tool resolution (i.e. 0.5 feet). This in turn leads to unrealistic movement of water in the model, pre-mature water breakthrough, pessimistic forecast of oil and gas and over-estimation of required water treatment system capacity. Although some advancement has been made in the identification of these types of reservoirs, their reservoir modeling still remains a challenge for petroleum industry due to limitations in developing proper methods to estimate petrophysical properties using conventional logs and also the computational cost of running extremely fine numerical models. In this study various issues and challenges of modeling these types of reservoirs are addressed. A workflow for numerical modeling of thinly laminated sands at affordable vertical grid resolutions has been proposed that properly uses the available geological, petrophysical and engineering data in an effective (vs. total porosity) system. The methodology of reproducing the volumetrics and capturing heterogeneity at various scales, through proper rock-typing and use of net to gross ratios are discussed in detail. The data requirement for modeling, reservoir management and performance monitoring of thin beds is also elucidated. The presented workflow provides a simple yet pragmatic tool that can help best represent the thinly laminated sands at affordable measurement and computation costs, mitigate the risks associated with thin bed reservoir development and increase the value of field development planning.

Surfactants have the ability to overcome the capillary forces restricting mobilization of oil in the porous media. Generally, the application of surfactants in harsh reservoir conditions has been avoided, due to the challenges accompanying their implementation in such conditions. In this paper, the performance of a mixture of Alkyl Ether Carboxylate (AEC) and Alkylpolyglucoside (APG) was experimentally investigated in harsh reservoir conditions. A Malaysian offshore field with challenging conditions has been studied in this present work, with a reservoir temperature of 106°C and injection water salinity of 32,000 ppm. The investigations were made using surface tension, interfacial tension and partitioning experiments. Surfactant concentration was measured throughout the partitioning test using High Performance Liquid Chromatography (HPLC). The results of the surface tension test showed that the CMC for AEC:APG mixture was approximately 0.13 wt% at 106 °C. IFT results showed that the presence of the surfactant mixture was capable of reducing the IFT between crude oil and brine, and achieve low IFT value (0.035 mN/m) in such harsh conditions. Partitioning test results explained the partitioning behaviour of the surfactant molecules into the oil-water interface. Additionally, surfactant concentration, brine/oil ratio and salinity have a significant impact on surfactant partitioning. The results corresponded to the interfacial tension behaviour, where the lowest IFT value was observed at the highest kp value for the AEC:APG mixture. This concluded that the partitioning coefficient can be directly related to interfacial tension. Furthermore, the increase of the brine/oil ratio as well as the salinity, portrayed an increasing trend of the kp values. The findings of this study showed promising outcomes for future implementation of surfactant flooding in such harsh conditions. By using the proposed surfactant mixture, potential success becomes likely for surfactant flooding application in this study under harsh reservoir conditions.

The application of surfactants in Enhanced Oil Recovery (EOR) has over the years, revealed various challenges that impose limitations on successful implementation of surfactant flooding. Surfactant adsorption is one of the major criteria that strongly dictates the feasibility of surfactant flooding in chemical enhanced oil recovery (CEOR). This paper presents the impact of the presence of crude oil on surfactant adsorption and the influence of surfactant partitioning on the adsorption quantification. In this study, static adsorption experiments were conducted for a mixture of Alkyl Ether Carboxylate (AEC) and Alkylpolyglucoside (APG) in the absence as well as the presence of crude oil. Partitioning experiments were carried out to evaluate the surfactant partitioning between the aqueous surfactant solution and the crude oil, in order to determine the partitioning influence on the adsorption results in the presence of crude oil. The mixture’s adsorption and partitioning behaviors were studied at a fixed salinity of 32,000 ppm and temperatures of (80 °C and 106 °C). High Performance Liquid Chromatography (HPLC) was utilized in measuring the surfactant concentration throughout adsorption and partitioning tests. X-ray photoelectron spectroscopy (XPS) and X-ray diffraction (XRD) were utilized for rock characterization prior to and after adsorption with and without crude oil being present. Static adsorption outcomes displayed the adsorption of APG, AEC, and the overall mixture with and without crude oil being present, as all having a similar increasing trend as concentration increases. However, the adsorption values were much higher when crude oil was present as compared with the adsorption values when crude oil was absent; this is due to not considering the impact of surfactant partitioning. A significant amount of what was adsorbed belongs to AEC due to its increased chain–chain interactions with APG; hence, AEC is the greatest contributor in the overall surfactant mixture’s adsorption. Also, the AEC:APG mixture was affected by temperature increase, showing that APG has a greater sensitivity to temperature in comparison to AEC. The surfactant partitioning results were used to validate the surfactant adsorption outcomes in the presence of crude oil. After eliminating the partitioning effect, the surfactant adsorption isotherms in the presence and absence of crude oil were almost identical. The results highlighted the importance of measuring surfactant partitioning, and the impact that partitioning has on the total surfactant losses during the surfactant flooding process. XRD and XPS results explained that the change of the rock structure after adsorption in the presence of crude oil was due to the rock dissolution phenomena. It was concluded that adsorption and partitioning take place in the water/oil/rock system simultaneously, and taking that into account allows for the improved and proper designing of the surfactant flooding.

A major Malaysian matured offshore oilfield which is currently under waterflooding has been seen declining in production in recent years. Among various enhanced oil recovery (EOR) techniques evaluated, this field appears to be amenable to chemical EOR implementation. Chemical EOR project requires high capital and operating expenditure (CAPEX and OPEX) and often involve complex logistical and operational challenges in an offshore environment. A comprehensive study and technical road map plan from laboratory to pilot and then to full field reservoir simulation model has been established to reduce the project risks prior to field-scale chemical EOR implementation. For this study, detailed EOR screening and ranking evolution is conducted and confirmed that chemical EOR is ranked high among other EOR techniques and stands for better chance of success techno-economically. Subsequently, all the relevant field examinations to verify the incremental oil recovery from chemical EOR including extensive laboratory experiments such as fluid-fluid and fluid-rock evaluations and pilot tests by single well chemical tracer method were designed and implemented. This paper mainly presents the challenges and the strategies to build a realistic full field chemical EOR numerical simulation model (using CMG's STARS), which include history matching and waterflooding optimization process stages. The work has been carried out to address the best practice workflow for chemical EOR simulation, lessons learned from how to properly prepare and incorporate the chemical input data, identify uncertainties relate to project risks and minimize or mitigate the impact of risks to the project economics. Numerical simulation was utilized along with assisted optimization methods that combine experimental design and artificial intelligence (AI) techniques (using CMG's CMOST) to determine injection chemical concentration and chemical slug size for optimal oil recovery factor and project net present value (NPV). Sensitivity studies were also performed with the reservoir simulation models to determine the impact of effects such as residual oil saturation (Sor) reduction, chemical loss through adsorption, dilution effects on capillary number, salinity and viscosity effects, cooling effects, chemical reactions, among others. The study results show that chemical EOR injection is a technically feasible and economically viable option for this oilfield from subsurface, incremental oil recovery, and facilities stand points. Furthermore, the results of this risk assessment will facilitate and expedite the full field project execution and investment plan in future.

SummaryA surfactant alternating gas (SAG) process is often the injection method for foam, on the basis of its improved injectivity over direct foam injection. In a previous study, we reported coreflood experiments on liquid injectivity after foam flooding and liquid injectivity after injection of a gas slug following steady-state foam. Results showed that a period of gas injection is important for the subsequent liquid injectivity. However, the effects of multiple gas and liquid slugs were not explored.In this paper, we present a coreflood study of injectivities of multiple gas and liquid slugs in an SAG process in a field core. Nitrogen and surfactant solution are either coinjected or injected separately into the sandstone core sample. The experiments are conducted at an elevated temperature of 90°C with a backpressure of 40 bar. Differential pressures are measured to quantify gas and liquid injectivities. Computed tomography (CT) scanning is applied to relate water saturation to mobility.During the injection of a large gas slug following foam, a bank in which foam completely collapses or greatly weakens forms near the inlet and propagates slowly downstream. During the subsequent period of liquid injection, liquid flows through the collapsed-foam bank much more easily than further downstream. Beyond the collapsed-foam region, liquid first imbibes into the whole cross section. In this region, liquid flows mainly through a finger of high liquid saturation. Our CT results suggest a revision of our earlier interpretation; the process of gas dissolution does not merely follow fingering but is evidently directly involved in the fingering process.Our results suggest that, in radial flow, the small region of foam collapse very near the well greatly improves injectivity. The subsequent gas and liquid slugs behave near the wellbore, affecting injectivity, in a way similar to the first slugs. Thus, the behavior and modeling of the first gas slug and first subsequent liquid slug is representative of near-well behavior in an SAG process. The trends observed in our previous work are reproduced in a low-permeability field core.

Blowouts have catastrophic consequences and can potentially occur during any exploration or development projects. The situations that could lead to a blowout are underestimated pore pressure, rapid change in pressure, abnormal pressure or operation complexities such as complete fluid loss and thief zones. Blowouts are the most destructive and dangerous disaster in the oil and gas operations. Apart from causing fatalities and injuries, a blowout also causes ecological and environmental damages. While there is remedial work that can be done to manage the side effect of a blowout, an analysis has to be done to evaluate the extent of the damage. The oil spill analysis has to include all parameters and take into consideration all scenarios which would cater for the remedial work needed to address the aftermath of the blowout. In this paper, the entire spill process beginning from the reservoir up to the surface is reviewed. The review covers the phenomenon involved in a spill process, the related HSE concerns, remedial work and spill modelling. The initial conditions, boundary conditions, and media transfer functions such as porous media properties, sand face and wellbore geometry are fully captured in the study and is reflected in the workflow. These parameters would affect the plume shape, size and geometry, blowout duration and oil spill volume estimation. The workflow presented in this paper is an effective technique for efficient decision making and remedial work in case of an oil spill resulting from an uncontrolled blowout.

Surfactant-alternating-gas (SAG) is a preferred method of foam injection, which is a promising means of enhanced oil recovery. Liquid injectivity in a SAG process is commonly problematic. Our previous studies suggest that the liquid injectivity can be better than expected due to the existence of a collapsed-foam region formed during the gas-injection period ahead of the liquid-injection period. A single superficial velocity was used in those studies to examine the flow behavior during gas- and liquid-injection periods, separately. However, in radial flow from an injection well, superficial velocity decreases with distance from the injection well. Understanding the effect of superficial velocity on gas and liquid injectivities is important, but remains unexplored. In this study, we first examine gas injection at different superficial velocities following foam injection. We then study the effect of liquid superficial velocity on the liquid injectivity following a similar volume of gas injection. Our results show that during a prolonged period of gas injection following foam, the propagation velocity and the total mobility of the collapsed-foam bank are not significantly affected by the gas superficial velocity. During liquid injection after a period of gas injection, the dimensionless propagation velocities and the total mobilities of the forced-imbibition bank and the gas-dissolution bank follow a power-law dependence on the liquid superficial velocity. Liquid fingering through the weakened-foam region shows strongly shear-thinning behavior. It is also observed from X-ray computer-tomography experiments that the liquid fingers are wider if the liquid superficial velocity is greater. The impact of the shear-thinning behavior on the estimation of liquid injectivity in a field application is the subject of a companion paper.

Uncertainty and risk analysis is an inseparable part of any decision making process in the field development planning. This study sheds light on the available approaches to capture the range of uncertainties but digs deep into the misuses of the probabilistic approach that renders the method difficult and time consuming to implement with little added value for risk mitigation and proper decision making. Probabilistic modeling using dynamic simulation models has been adopted in recent decades to address the variations in forecasted production profiles and to capture the uncertainties. However, there are misuses in the approach that pose questions on the outcome and its meaningfulness. Lack of enough spread in the forecast, history-matched models with physically incorrect parameter ranges/ combinations and models suggesting contradicting development scenarios are among examples. These in turn make the probabilistic forecasting output inconclusive and considering the high computational cost and time required to perform the exercise makes it unattractive to management. In this paper four case studies including mature and green fields have been described and a number of main issues and pitfalls of using probabilistic dynamic modeling in those cases are analyzed. General workflows are then presented for green and brown fields based on experimental design, proxy modeling, optimization and prediction candidates selection that provides solution for proper selection and implementation of the probabilistic dynamic modeling. It is argued that probabilistic modeling can help better capture the uncertainties and reduce the risk in field development planning provided that a fit-for-purpose approach is taken with correct understanding of the data requirement according to the reservoir complexity, the physical processes being modeled and assumptions used in the methodologies and simulation engines. This is in contrast to the attempts to capture the ranges of recoverables based on deterministic high and low cases that is often inefficient as the optimistic high-case of ‘hole-in-one’, may suggest an ideal but not plausible scenario whereas the pessimistic low-case of ‘train-wreck’ may be economically unattractive. The exercise then leaves the companies with the best technical estimate model to make the final call and the numbers from other models are only used for reserve booking purposes. The published papers in the literature include discussions on deterministic vs. probabilistic approaches and selection of base case models, the detailed algorithms and also case studies done using the published methods available in the commercial softwares. This paper however discusses the misuses of the probabilistic dynamic modelling approach and tries to inform the audience of the pitfalls of not understanding the reservoir and/or the tools used in implementing the methods and in this sense it is novel.

This paper discusses about a systematic approach of probabilistic dynamic modeling which was used to assess subsurface uncertainties, and to forecast range of ultimate recovery (P90, P50, and P10) for infill and EOR opportunity (immiscible Water-Alternating-Gas, iWAG) in a mature offshore oilfield. The field is very complex, with multi-layered and highly compartmentalized reservoirs and has been on production under natural depletion since the last 47 years. It is in "mid-life crisis", facing problems of high watercut and GOR, with bypassed oil areas and pressure depletion, and therefore in need for redevelopment to increase its recovery factor. However, despite the long production history, subsurface uncertainties remain high due to its reservoirs complexity and limited reservoir data. To assess the subsurface uncertainties and their impact on field redevelopment plan, a fine-scaled sector model was built for a focused area of the field with substantial remaining opportunity. Multiple static realizations were used to represent different reservoir connectivity that can be highly influential on the ultimate recovery, especially for iWAG injection. Along with these multi-static realizations, key dynamic uncertainties such as fault transmissibility, kv/kh, aquifer properties, etc. were also incorporated. It is very important to note that uncertainty parameters may vary between history matching and forecast period, especially when there is a change in drive mechanisms. Therefore, additional uncertainty parameters such as residual oil saturation (Sorw, Sorg), in the case for iWAG scenario, have also been included from the very beginning to ensure seamless transition from history matching up to forecasting. Another big challenge to conduct probabilistic dynamic modeling in a mature field is, to generate multiple equally probable history matched realizations for subsequent proxy modeling and probabilistic forecasting. The uncertainty and optimization (U&O) modeling tools, including experimental designs, have made this possible and proven to be the most efficient way to speed up the modeling process. It has helped to generate the physical P90, P50, and P10 dynamic models that could be used to assess the robustness of various development options, hence able to deliver the optimum strategies while managing subsurface uncertainties. All these proved to be a comprehensive probabilistic workflow to firm up several sizeable infill and injection portfolios in this complex mature field, with potential to increase recovery factor by 8% to 13%. Most importantly, decision makers were given a range of outcomes instead of a deterministic forecast, allowing proper risks mitigation plans to be devised to deliver a robust project definition and superior performance.

Poor conformance and unfavourable mobility ratio in the reservoir are common issues that hinder effective oil production and recovery. These issues are often exacerbated when the displacement is associated with viscous oil driven by water in highly permeable porous media. One of the reservoirs located onshore in East Africa suffers from this issue of high bypassed oil due to the presence of viscous oil, i.e. viscosity of 20 cP and API gravity of 28°. Most of the produced wells were observed to experience early water breakthrough and suffered from high water cut at present. In view of this phenomenon, Alkaline-Surfactant-Polymer (ASP) flooding was proposed to recover the remaining oil that is bypassed and trapped underneath. Through laboratory evaluation, the main objective of this study was to generate an effective chemical concoction comprising of alkaline, polymer and surfactant which are compatible to the formation fluids and rocks for the targeted reservoirs. The laboratory works were conducted based on a comprehensive and systematic workflow. Sample characterization and fluid-fluid analysis at the early phase encompass the studies of phase behaviours, physico-chemical properties, thermal stability etc. These studies aimed to screen off the chemical candidates which did not fulfill the corresponding Key Performance Indicators (KPI). The successful ASP formulations were subsequently optimized in terms of their respective concentrations without sacrificing the technical performance. Fluid-rock analysis aimed to quantify the oil recovery potential and reduction of residual oil saturation through coreflood experiments. Due to the high Equivalent Alkane Carbon Number (EACN) of the crude oil, i.e. 19 (nonadecane), and ultra-low salinity of formation water, i.e. 950 ppm, the greatest technical challenge in this study was to identify an effective surfactant which could reduce the water-oil interfacial tension (IFT) significantly under the operating range. Despite the challenges, an optimized ASP formulation, with a concentration of 0.5 wt.% of alkali, 0.2 wt.% of surfactant and 0.2 wt.% of polymer, successfully fulfilled all of the required KPI. The coreflood results indicate a reduction of residual oil saturation more than 30 % of Oil-In-Place. With these encouraging laboratory results, it could lead to the prospect of pilot and detailed Field Development Plan (FDP) studies, which could further de-risk the chemical EOR projects in this region.

The increasing atmospheric concentration of carbon dioxide (CO2), a greenhouse gas (GHG) is creating environmental imbalance and affecting the climate adversely due to growing industrialization. Global leaders are emphasizing on controlling the production of GHG. However, growing demands of natural gas, industry is embarking on the development of high CO2 contaminant gas fields to meet supply gap. Development and management of contaminated hydrocarbon gas fields add additional dimension of sequestration of CO2 after production and separation in project management. CO2 sequestration is a process for eternity with a possibility of zero-degree failure. Monitoring, measuring and verification (MMV) of injected CO2 volume in sequestration is critical component along with geological site selection, transportation, storage process. The present study discusses all the impacting parameters which makes whole process environment friendly, economically prudent and adhering to national and international regulations.The migration of injected CO2 plume in the reservoir is uncertain and its monitoring is equally challenging. The role of MMV planning is critical in development of high CO2 contaminant fields of offshore Sarawak. It substantiates that injected CO2 in the reservoir is intact and safely stored for hundreds of years after injection and possesses minimum to no risk to HS&E. The deployment of Multi-Fiber Optic Sensor System (M-FOSS) promises a cost-effective solution for monitoring the lateral & vertical migration of CO2 plume by acquiring 4D DAS-VSP (Distributed Acoustic Sensor – Vertical Seismic Profile) survey and for the well integrity by analyzing DAS/DTS (Distributed Temperature Sensor)/DPS (Distributed Pressure Sensor)/DSS (Distributed Strain Sensor) data.Simulation results and injectivity test at laboratory for in-situ CO2 injection has demonstrated the possibility of over 100MMscfd/well injection in aquifer to meet the total CO2 injection of 1.2Bscfd for full field development while maintaining the reservoir integrity. Uncertainty & risk analysis shows possible presence of seismically undistinguished fractures and minor faults, an early breakthrough of injected CO2 cannot be ruled out. The depleted reservoir storage study divulges the containment capacity of identified carbonate reservoirs as well as conformance of potential storage sites. The fault-seal analysis and reservoir integrity studies determine the robustness of the long-term security of the CO2 storage. Injectivity study demonstrates the optimum and maximum possible rates of CO2 injection into these depleted gas reservoirs. VSP simulation results show that a subsurface coverage of 3-4 km2 per well is achievable, which along with simulated CO2 plume extent help to determine the number of wells required to get maximum monitoring coverage for the MMV planning. The deployment of M-FOSS technology is novel and proactive approach to monitor the CO2 plume migration and well integrity. First ever development of MMV Planning for CO2 Sequestration in offshore Sarawak, Malaysia using novel and cutting-edge M-FOSS technology for proactive monitoring of CO2 plume migration and well integrity.

Reservoir heterogeneity and permeability contrast are some of the factors that affect the efficiency of EOR applications in the field. The main issues of current secondary and tertiary recovery methods such as water, gas, or water-alternating-gas (WAG) injections in the field are poor mobility control, gravity segregation, and viscous fingering, among others. Displacement conformance needs to be improved as to ensure that target regions are properly swept. To address these issues, foam has been proposed to complement the existing EOR applications, with the target to improve overall sweep efficiency through the reduction of gas mobility. However, very limited data of this effect are available on the actual reservoir rocks under field conditions. In this paper, laboratory research work was conducted to capture the effect of heterogeneity on foam using actual reservoir rocks of varied permeabilities. It is observed that foam is more stable in high permeability cores compared to low permeability cores. Our finding in actual reservoir rocks is consistent with the literature observations conducted in outcrop core samples. Moreover, we used a texture-implicit-local-equilibrium model to parameterize our foam system. Mobility reduction of the gas phase by foam was found to be selectively higher in cores of higher permeabilities. Another finding from the model is that, in all cases, the parameter epcap, which regulates the significance of shear-dependent rheological behavior, approximately equals to 1. Foam exhibit Bingham-like fluid properties where pressure gradient is irrelevant to the shear rates. We also simulated our foam system in a hypothetical two-layered model reservoir using MoReS. We systematically compared the oil displacement by water-alternating-gas (WAG, no foam) process and by surfactant-alternating-gas (foam) process. It is concluded that foam can effectively improve the conformance of the oil displacement in presence of reservoir heterogeneity. The permeability-dependent foam rheology can divert the displacing fluids from the high-permeability region to the low-permeability region and therefore enhancing the overall oil recovery efficiency.

Underground storage of CO2 in depleted gas reservoirs is a greenhouse gas reduction technique that significantly reduces CO2 released into the atmosphere. Three major depleted gas reservoirs in Central Luconia gas field, located offshore Sarawak, possess good geological characteristics needed to ensure long-term security for CO2 stored deep underground. Long-term integrity of all the wells drilled in these gas fields must be ensured in order to successfully keep the CO2 stored for decades/centuries into the future. Well integrity is often defined as the ability to contain fluids without significant leakage through the project lifecycle.In order to analyze the risk associated with all 38 drilled wells, that includes 11 plugged and abandoned (P&A) wells and 27 active wells, probabilistic risk assessment approach has been developed. This approach uses various leakage scenarios, that includes features, events, and processes (FEP). A P&A well in a depleted reservoir is a very complex system in order to assess the loss of containment as several scenarios and parameters associated to those scenarios are difficult to estimate. Based on the available data of P&A wells, a well has been selected for this study. All the barriers in the example well have been identified and properties associated with those barriers are defined in order to estimate the possible leakage pathways through the identified barriers within that well. Detailed mathematical models are provided for estimating CO2 leakage from reservoir to the surface through all possible leakage pathways.Sensitivity analysis has been carried out for critical parameters such as cement permeability, and length of cement plug, in order to assess the containment ability of that well and understand its impact on overall well integrity. Sensitivity analysis shows that permeability of the cement in the annulus, and length of cement plug in the wellbore along with pressure differential can be used as critical set of parameters to assess the risk associated with all wells in these three fields.Well integrity is defined as the ability of the composite system (cemented casings string) in the well to contain fluids without significant leakage from underground reservoir up to surface. It has been recognized as a key performance factor determining the viability of any CCS project. This is the first attempt in assessing Well Integrity risk related to CO2 storage in Central Luconia Gas Fields in Sarawak. The wells have been looked individually in order to make sure that integrity is maintained, and CO2 is contained underground for years to come.

This paper investigates the effect of rock permeability on foam transport in porous media both at the core-level and at the field level for enhanced oil recovery (EOR) applications. Foam offers promise to simultaneously address the issues that limit the overall oil recovery efficiency of water-alternating-gas (WAG) process such as viscous fingering, gravity override, and reservoir heterogeneity. However, in the literature, limited foam data were reported using actual reservoir cores at harsh conditions. In this paper, a series of methane (CH4) foam flooding experiments were conducted in 3 different actual cores from a proprietary reservoir at elevated temperature. It is found that foam strength is significantly correlated with rock permeability. We calculated the apparent viscosity based on the measured pressure drop along the core samples at steady state. The calculated apparent viscosity was found to be selectively higher in cores of high permeabilities compared to that in cores of low permeabilities. We parameterized our foam system using a texture-implicit-local-equilibrium model to understand the dependence of foam parameters on rock permeability. In addition, we established a 2-layered heterogeneous model reservoir in the Shell in-house simulator called MoReS (Modular Reservoir Simulator) to systematically study and compare the driving forces for fluid diversion during foam flooding at the field level including the gravitational force, the viscous force, and the capillary force. During the WAG process, gravitational force kept the gas from sweeping the lower part of the reservoir. The gravity can be overcome by viscosifying the gas with surfactant solution. In addition, capillary pressure which hinders the gas from entering the low permeability region can actually redistribute the two phases during foam EOR and improves the sweep efficiency. It is concluded that foam can effectively improve the conformance of the WAG EOR in the presence of reservoir heterogeneity.