The capability of commercial nanoparticles to perform as foam stabilizer were investigated at reservoir temperature of 96°C. Al 2 O 3 , Fe 3 O 4 , Co 3 O 4 , CuO, MgO, NiO, ZrO 2 , ZnO and SiO 2 nanoparticles that were characterized using XRD, FTIR, FESEM-EDX, TEM and PSA, were blended in the in-house formulated surfactant named IVF respectively at a particular ratio. The test was performed with and without the presence of reservoir crude oil. Results showed that formulation with nanoparticles enhanced foam stability by having longer foam half-life than the IVF surfactant alone, especially in the absence of oil. Only SiO 2 nanoparticles were observed to have improved the foam stability in both test conditions. The unique properties of SiO 2 as a semi-metal oxide material may have contributed to the insensitivity of SiO 2 nanoparticle towards crude oil which is known as a foam destabilizer. The physical barrier that was formed by SiO 2 nanoparticles at the foam lamella were probably unaffected by the presence of crude oil, thus allowing the foams to maintain its stability. In thermal stability tests, we observed the instability of all nanoparticles in the IVF formulation at 96°C. Nanoparticles were observed to have separated and settled within 24 hours. Therefore, surface modification of nanoparticle was done to establish steric stabilization by grafting macro-molecule of polymer onto the surface of SiO 2 . This in-house developed polymer grafted silica nanoparticles are named ZPG nanoparticles. The ZPG nanoparticles passed the thermal stability test at 96°C for a duration of 3 months. In the foam wetness analysis, ZPG nanoparticles were observed to have produced more wet foams than IVF formulation alone, indicating that ZPG is suitable to be used as foam stabilizer for EOR process as it showed catalytic behaviour and thermally well-stable at reservoir temperature.

This paper is based on the analysis of miscible WAG for an onshore Middle-East field, with strongly undersaturated light oil. Water Alternate Gas operations have been ongoing for around 5 years, which is relatively recent compared to more than 40 years of production history. Goal of this work was to assess the efficiency of this miscible hydrocarbon WAG and to optimize it on the different compartments, with respect to miscibility, voidage replacement, and recycling. As this is a large mature field, with WAG operations dispatched on around 50 injectors and 9 fault blocks (compartments), the method of analysis had to be robust with respect to the different injection strategies followed in the past. It was essentially based on injection and production data, but also used pressure data when available. We computed the following dimensionless variables: oil recovery factor, BSW, voidage replacement ratio (VRR), and also WAG ratio and gas recycling ratio (GRR). Their evolution versus time was analyzed and compared between fault blocks. Using dimensionless variables allowed to compare fault blocks with different initial volumes in place, and to illustrate trends versus time. It was also found beneficial to lump some compartments, when communication was substantiated by pressure data. On the production side, we used the conventional BSW and GOR variables to quantify the water and gas recycling ratio. On the injection side, we observed that in some compartments, the historical WAG ratio was too low in the oil zone, which could be quantified by excluding the peripheral water injection volumes. The analysis allowed also to estimate the gas utilization factor and efficiency, which confirmed the overall high efficiency of miscible gas injection in 3-phase mode. It was also found that the injected fluid efficiency correlated with geology: gas injection tends to be more efficient in zones with high permeabilities at the bottom (coarsening downwards), while water injection is better adapted to zones with high permeabilities at the top (coarsening upwards). Estimating these water and gas efficiencies also allowed to optimize the injection strategy on a field level, by comparing the water efficiency with other units of the field only under waterflood.

Foam Enhanced Oil Recovery (EOR) has been employed as an improved recovery method due to its best sweep efficiency and best mobility control over the other injection method such as gas flooding, water flooding and other EOR methods. Foam which has high viscosity illustrates great potential for displacing liquid. The relative immobility of foam in porous media seems to be able to suppress the formation of fingers during oil displacement leading a more stable displacement. However, there are still various parameters that may influence the efficiency of foam assisted oil displacement such as oil properties, permeability of reservoir rock, physical and chemical properties of foam, and other parameters. Also, the interaction and displacement patterns of foam inside the porous media are remained unknown. Thus, in this study, we investigated the three-dimensional (3D) characteristics of oil recovery with gases, water, surfactant, and foam injection in a porous media set-up. By using CT scanning machine, the fluid displacement patterns were captured and analyzed. Moreover, the effect of oil viscosity on foam displacement patterns is studied. The study provides a qualitative and quantitative experimental visualization of 3D displacement structure, oil recovery with gases, liquid and foam injection. As a result, the comparison of fluid displacement patterns between gases, water, surfactant and foam injection show that foam has the good ability in sweeping and forms stable displacement front. The combination of surfactant, liquid and gas, which makes up foam resulted in a synergistic effect in oil displacement. On the other hand, viscous fingering, gravity segregation, trapped oil phenomena are shown in gas flooding and liquid flooding experiments. Thus, foam which displaced stably across the permeable bed resulted in the highest oil recovery factor. The mechanism of foam flow in porous media was understood in this study. Foam, as a series of bubble, burst and become free moving liquid and gas particles when in contact with oil and porous media. Therefore, two displacement fronts could be found from the foam injection experiment, in which the front layer moving ahead in contacting with oil bank is the discontinuous gas/liquid layer and followed by stably foam bank at the back. Due to the stable displacement of foam bank, the effect of oil viscosity on foam displacement is suppressed and showed no distinction in terms of displacement patterns. The flow regimes are found to be the same despite different viscosity of displaced oil. There has been no linear correlation proved between the oil viscosity and oil recovery factor.

In line with ADNOC Sustainability policy, reduction of GHG emissions, AGP has initiated projects for recovery of CO 2 from existing plants. The extracted CO 2 is planned to be used for Enhanced Oil Recovery. The current paper highlights method used for evaluation of various location and technology options for implementation of the new CO 2 recovery units, considering existing plants flow schemes along with their interfaces and associated challenges. Key Performance Indicators (KPIs) were identified based on Inherent Safety, Economics, Technology Maturity, Product Quality, Operability / Flexibility, Constructability. Identified options were further developed and subsequently evaluated based on preliminary economic analysis and available technical information. Accordingly, weighted scores of the KPIs developed for option selection. Major criteria used for ranking were unit cost of CO 2 product, adherence to required H 2 S and COS specifications, technology maturity and deployment in industry. For one location, the options considered included installation of new Acid Gas Removal Unit (AGRU) upstream of existing AGRU, revamp of existing Acid Gas Enrichment Unit (AGEU), new AGEU, and direct feed of Acid gas to new CO 2 recovery unit to supplement falling upstream reservoir profile. For another location, the options included new CO 2 recovery plant upstream of existing Sulphur Recovery Unit (SRU) or downstream of existing Tail Gas Treatment Unit (TGTU), compression of TGTU gases upstream of proposed CO 2 recovery unit, installation of new unit downstream of existing incinerators, combination of CO 2 recovery units of both plants, were also assessed. In addition, new CO 2 Dehydration and Compression units considered to meet CO 2 product specifications and B/L requirements. Based on project requirements, physical methods of CO 2 removal like membranes and molecular sieves deemed unsuitable. Further to discussions with various licensors, emphasis remained on chemical and physical solvent technologies. Based on assessment, solvent swap for AGEU (upstream of existing SRUs) with reduced lean solvent temperature at one location, solvent swap in TGTU followed by a new polishing unit at another location combined with common high pressure compression facility, was selected for engineering development.

A major matured Malaysian offshore oilfield with more than 40 years of production history under a combination of moderate to strong aquifer support and moderate-size gas cap will be subjected to a unique enhanced oil recovery (EOR) scheme, the first of its kind offshore, called Gravity Assisted Simultaneous Water Alternating Gas (GASWAG) injection process. It is essentially a scheme which involves simultaneously injection of gas and water which involves injecting water up-dip and gas down-dip structurally in a depleted oil reservoir. This method takes the advantage of gravity drainage mechanism to maximize recovery from un-swept oil zones down-dip by aquifer influx and up-dip by gas cap expansion processes and it could be different than the conventional water alternating gas (WAG) method. This paper mostly presents the dynamic modelling and simulation work which has been established during this case study to obtain the GASWAG base case model and to conduct the optimization and sensitivity assessments on the major reservoir parameters. It also describes the main subsurface uncertainties and operational risks and their impact on incremental oil reserve and the results were used to design mitigation plans to help minimize impact on oil recovery volumes. Implementing the full field scale of this EOR scheme involves a detailed reservoir management plan (RMP) with many reactivations of idle wells, well workover plans, behind casing opportunities and adding perforation interval together with identified new infill wells to maximize the flood-front movement of the injected fluids. Obviously, good communication with field operational personnel is paramount to ensure these RMP are adhered to clear targets to successfully achieve the desired incremental recovery and will be elaborated in this paper. This paper describes the strategy and workflow to monitor and measure the two key success factors of this project which are production attainability and reserve attainability. The success of this project depends on continuous evaluation to check the actual performance against the anticipated behavior. As soon as new information obtains along implementation, it will be assessed against targets to steer the way to the main goal of additional reserve by the end of field life. Thus, it requires a comprehensive monitoring plan with detailed surveillance and data collection and, well testing to revisit and update the dynamic model accordingly. The results of this study show that GASWAG has emerged to be one of the most promising techniques with the highest incremental reserve for this field among various EOR techniques evaluated such as continuous gas injection, continuous water injection, conventional WAG, aquifer-assisted WAG, and double displacement.

Injecting carbon dioxide (CO 2 ) as foam during enhanced oil recovery (EOR) can improve injectate mobility and increase sweep efficiency. Integrating CO 2 -foam techniques with carbon capture, utilization and storage (CCUS) operations is of recent interest, as the mobility control and sweep efficiency increases seen in EOR could also benefit CO 2 storage during CCUS. In this study, a variety of different charge, hydrocarbon chain length, head group surfactants were evaluated by surface tension, bulk and dynamic CO 2 -foam performance assessments for CCUS. The optimal foam candidate was expected to provide satisfying mobility control effects under reservoir conditions, leading to an improved water displacement efficiency during CO 2 -foam flooding that favors a more significant CO 2 storage potential. All tested surfactants were able to lower their surface tensions against scCO 2 by 4-5 times, enlarging the surface area of solution/gas contact; therefore, more CO 2 could be trapped in the foam system. A zwitterionic surfactant was found to have slightly higher surface tension against CO 2 while exhibiting the highest foaming ability and the most prolonged foam stability with a relatively slower drainage rate among all tested surfactants. The dynamic performance of scCO 2 -foam stabilized by this zwitterionic surfactant was also evaluated in sandstone and carbonate cores at 13.79 MPa and 90°C. The results show that the mobility control development in carbonate core was relatively slower, suggesting a gradual foam generation process attributed to the higher permeability than the case in sandstone core. A more significant cumulative CO 2 storage potential improvement, quantified based on the water production, was recorded in sandstone (53%) over the carbonate (47%). Overall, the selected foam has successfully developed CO 2 mobility control and improved water displacement in the occurrence of in-situ foam generation, hence promoting the storage capacity for the injected CO 2 . This work has optimized the foaming agent selection method at the actual reservoir conditions and evaluated the scCO 2 -foam performance in establishing high flow resistance and improving the CO 2 storage capacity, which benefits integrated CCUS studies or projects utilizing CO 2 -foam techniques.

Modelling unstable displacement is a challenge which may lead to large errors in reservoir simulations. Field scale coarse grid simulations therefore need to be anchored to more reliable fine grid models which capture fluid displacement instabilities in a physically correct manner. In this paper, a recently developed approach for accurately modelling viscous fingering has been applied to various types of unstable displacement. The method involves estimation of dispersivity of the porous medium and length scale of the model to determine the required size of the simulation grid cell. Fractional flow theory is then applied to obtain the correct saturation of the injected phase in the unstable fingers formed due to the adverse mobility ratio. Unstable displacement experiments have been history matched using 2D-imaging of in-situ saturation as a calibration of our method, before carrying out sensitivity calculations on the effect of fluid viscosity, and rock heterogeneity. Our modelling approach allows us to carry out simulations using a conventional numerical simulator using elementary numerical methods (e.g. single-point upstreaming). The methods used to model instability ( Sorbie et al, 2020 ) was originally developed for immiscible water/oil systems. The current paper now presents new results applying this approach to unstable gas displacements, where adverse viscosity ratios may be even higher than in water/oil systems. The displacement with injected gas is shown to be influenced by mass exchanges between the gas and oil as the alternating fluids (water and gas) are injected in WAG processes. Swelling of fingers delay the gas front and WAG processes divert the injected gas and improve sweep efficiency. We have also modelled water-oil displacement at adverse mobility and shown the benefit which is obtained by reducing the instability by adding polymers to viscosify the injected water. The impact of rock heterogeneity has different effect depending on buoyancy forces and the degree of crossflow into the high permeable zones. This paper extends our novel approach to modelling the fine scale distribution of the injected fluids in adverse mobility ratio displacements. This approach has now been applied to both, gas/oil and water/oil systems where viscous fingering is present, either at extremely adverse mobility ratios and/or for reservoirs where the permeability field is very heterogeneous.

South Oman has several pre-Cambrian reservoirs that are highly pressured (400-1000 bar), deep (3-5 km) and critically sour (H2S up to 10%). The combined STOIIP of these reservoirs makes it one of the largest gas EOR projects in the world. The objective here is to highlight the key performance indicators and digitalization techniques used for continuous and effective well, reservoir and facility management (WRFM) and production optimization, while honoring the facility constraints and gas export requirements. Real time pressure data such as tubing head pressures, injection/production rates along with other data including maps, static pressures and production logs are used to define an appropriate set of performance metric at various levels, e.g. reservoir, sector or well. Digitalization of surveillance data helps in real time production optimization such as offtake management based on creaming curves according to gas sink availability and facility constraints. Key business performance indicators include gas utilization efficiency; MGI performance indicators include incremental oil, throughput, instantaneous and cumulative voidage replacement ratios, gas breakthrough level and time, ratio of reservoir pressure to the target minimum miscibility pressure; and facility constraints are optimized through gas balance, along with tracking field performance against the initial FDP forecasts. Real time performance data is tracked using a commercial Real-Time Data Analysis tool (RTDA) and Database Analytics Visualization Tool (DAVT), with surveillance indicators targeted at well, reservoir and facility level. The above-defined Key Performance Indicators (KPI) are tracked against predictions from the field development plan in web-based portal developed at PDO (Nibras). Digitalization has enabled quick and effective monitoring of these KPI, short-term optimization of injection distribution and offtake rates to maximize oil production and overall value within facilities constraints and varying export gas commitments based on South Oman Gas Line (SOGL) network optimization. Using dimensionless plots and a standardized set of parameters help in developing a common understanding and benchmarking the MGI reservoir response with analogs and amongst different reservoirs. This work presents a set of performance KPIs and short-term optimization methodology using digitalization and LEAN framework that are tracked in a web-based portal, RTDA and DAVT. It provides means to facilitate offtake decisions to meet variable export requirements while honoring facilities constraints, assess reservoir performance, providing valuable insights that helps in speedy reservoir management decisions. This process has been replicated across PDO for all related MGI projects and can benefit other development types, e.g. chemical/steam injection.

Challenges in the design of efficient EOR field pilots have been discussed and documented in the industry, particularly when it comes to optimization of monitoring plans for technical and economical perspectives. This paper explores the benefits of pilot planning where the monitoring/control strategies are included in the early stages of the design to reduce risk of measurements ambiguity and ensure good quality pilot results evaluation. It addresses the use of new and existing technology in monitoring by highlighting the advantages and challenges of each alternative including potential pairing of complementary options to achieve the pilot objectives including illustration of the use of continuous and sporadic measurements on the evaluation. The proposed approach starts with a review of reservoir performance, heterogeneity and pilot objectives to ascertain the plausible monitoring technologies/strategies to aid during the pilot de-risking, followed by the identification of adequate novel and mature monitoring options, which are specific to EOR type and measurement nature (permanent, time lapse, etc.). Advantages of incorporating the monitoring strategy as integral part of the pilot design, as well as evaluation of the effectiveness/viability in the presence of uncertainty of the selected monitoring alternatives are discussed providing a reference of suitable/plausible EOR specific technologies. The paper illustrates the importance of selecting monitoring alternatives that feed off each other and the importance of using fit-for-purpose evaluation algorithms and a digitally enabled, structured approach to analyze and democratize pilot results and enable actionable decisions in operations.

The presence of hydrogen sulphide (H 2 S) in produced reservoir fluids mandates precautions in the design and operation of the surface facilities. The toxicity and corrosive nature of H 2 S, and the need to prevent both plugging of reservoir formations and increasing the sulphur content of the produced oil dictates the criticality of forecasting and monitoring the volumes and concentrations of H 2 S flowing through the whole asset. Ensuring the concentration is within acceptable operational limits is critical to safeguard the overall asset and the integrity of the surface pipeline network. The objective of this study was to utilize a history matched Digital Twin Integrated Asset Model (IAM) to predict the volumes and concentrations of H 2 S in a field located offshore Abu Dhabi by modeling the multi-stage separation, H 2 S removal, and re-injection facilities for gas injection and gas lifts. The field consists of multiple stacked carbonate reservoirs sharing the same surface facilities. The proposed modelling of H 2 S removal strategy involved a series of steps beginning with the sweetening of the produced associated gas for fuel gas requirements and mixing the extracted H 2 S volumes with the gas injection and gas lift streams. The sweetening process effectively mitigated any potential asset integrity issues arising due to corrosion of the power generation system and other surface facility assets. The stripped H 2 S gas, re-combined with the remaining produced gas, was used for gas-lifts and reinjected into the lower reservoirs for pressure maintenance and enhanced oil recovery (EOR). A next-generation surface-subsurface coupled simulator was utilized for the modeling of this field including the full asset surface pipeline network, the H 2 S removal plant, bypass lines and re-injection facilities for gas injection and gas-lifts. The Digital Twin IAM approach provided a robust method for tracking and predicting the concentration and volume of H 2 S in the produced gas over a period of 50 years. The simulation allowed tracking the H 2 S from its initial location in the reservoirs, into the production wells, then through the pipelines, all the way to the surface facilities where the sweetening of the produced is handled. Moreover, the use of the Digital Twin allowed the verification of the disposal plan of the extracted H 2 S, showing that mixing it with the re-injection gas stream is a feasible option. Recommendations based on the model were provided to the production and facilities team, leading to a robust long-term field development plan that ensures asset integrity.

Foams are used in many oil and gas applications including conformance control during EOR processes, fracturing, and acidizing operations. Foams are defined as dispersions of gas bubbles into a continuous liquid phase. Typically, foams are generated when an injection gas such as nitrogen, carbon dioxide, or flue gas is mixed with an injection fluid containing a foaming agent. This method, however, requires a gas source to be present for foams to be generated. The objective of this study is to evaluate a new alternative technique for foam generation using two salt solutions. Nitrogen gas is generated as a result of the reaction of the two salt solutions at specific conditions. This generated nitrogen gas is then used for foam generation in porous media. The foam generated using the two salt solutions is tested in a microfluidic device (rock-on-a-chip) to study the gas mobility reduction in porous media. A Foam rheometer apparatus is also used to measure foam apparent viscosity when the two salt solutions are mixed with a foaming agent. The results are compared with those obtained when nitrogen gas is injected into the system independently in the absence of the two salt solutions. Results reveal that the amount of added salts significantly impact the produced nitrogen volume. Additionally, the test conditions especially the temperature, significantly impacts the reaction rate. The rate of nitrogen gas generation is directly proportional to the temperature when tested at 25-80°C. In addition, experiments demonstrate that the foams generated using the two salt solutions reaction have almost identical characteristics as those produced when nitrogen gas is injected into the foam rheometer apparatus independently. Both methods generate the same foams with comparable foam apparent viscosity. In the microfluidic system, the foam obtained using the two salt solutions in the presence of a foaming agent shows excellent resistance to gas flow and subsequently exhibit large gas mobility reduction. This experimental study, for the first time, confirms the ability of the two salt solutions reaction to generate nitrogen gas spontaneously upon contact under certain conditions. The generated gas is used to generate foams in the presence of a foaming agent. This newly proposed technique of foam generation could significantly impact many oil and gas operations including conformance control during EOR processes, fracturing, and acid stimulation operations.

Yanchang Oilfield conducts systematic research on nitrogen injection to enhance oil recovery. Through the research of this project, the energy supplement method of horizontal wells suitable for the study area is determined, and its injection system and process parameters are optimized and determined. The optimal energy replenishment method selected by the mine field test achieves the following economic and technical indicators: Provide a nitrogen suitability evaluation plan; Complete the nitrogen flooding matching process design of the target well; Complete the design of the injection-production plan for the target well; Compare with other energy supplement methods. Through the analysis of two supplementary energy methods of water injection and gas injection in indoor and similar reservoirs, the following understandings have been obtained: (1) Nitrogen is insoluble in water, slightly soluble in oil, good swelling, large elastic energy, is an inert gas, exists widely in the atmosphere, inexhaustible, inexhaustible, has a wide range of sources. (2) the recovery rate of nitrogen flooding is significantly higher than that of water flooding. (3) The field test results of water injection and nitrogen test in similar reservoirs show that the supplementary formation energy of nitrogen injection is suitable for the later development of Chang 64 and Chang 71 in the Haobasi oil field. (4) Compared with deep ultra-low permeability reservoirs, it is more economical to use nitrogen to supplement formation energy and change oil. The rate is higher. From the above analysis, it can be seen that the supplementary energy of Chang 64 and Chang 71 reservoirs in the Haobasi oil area should be nitrogen injection as the main supplement, and water injection as a supplement. Gas/water alternate injection is used to adjust the gas injection profile to slow down the escape of injected nitrogen. . Although water injection supplements the formation energy with greater uncertainty, it can be used as a technical means of fluidity control in the gas injection process and is relatively economical.

Effective gas utilization is critical to any gas injection development project to maximize recoveries for a given purchase of make-up gas, whilst reducing the Green Gas House (GHG) emissions. This paper describes the use of a fully implicit Integrated Production System Model (IPSM) for two inter-connected production system networks, coupling multiple, critically sour oil reservoirs undergoing Miscible Gas Injection (MGI) for Enhanced Oil Recovery (EOR) using produced sour gas from oil and condensate fields in South Oman. The IPSM model links sixteen reservoir models with varying levels of complexities to the facilities network. Complexities in the facilities include multiple nodal constraints that necessitate the use of an Equation of State model (EOS). The IPSM model honors the gas balance implicitly. Gas flood optimization includes prioritizing low GOR production wells (at reservoir and well level) whilst maintaining reservoir pressure above Minimum Miscibility Pressures (MMP). Development schedule optimization also helps in optimizing the compressor size, the key Capex component. Compositional modeling allows continuous tracking of souring levels at different nodes, providing integrity status of overall production system network. The current IPSM model helps in optimization of schedule for the phased development of the oil reservoirs and eventually the most efficient gas utilization. This has enabled low pressure operation in some reservoirs providing oil at very low unit technical cost while waiting for gas availability. Compositional tracking for H2S helps in operating the facilities within design limits whilst planning future developments to cater to this design. Some key parameters can be parameterized for quick sensitivity analysis for an informed decision making for business opportunities. The production potential of the system is also tracked to ensure there is a cushion in the system to deal with any unexpected changes. This feature helps in planning and optimizing the scheduled turn-around activities for these two inter-connected production system networks. The novelty of this work is collaboration across multiple disciplines, especially the surface and subsurface because of complex interactions between facilities constraints and reservoir performance (associated with produced gas reinjection). Compositional tracking and injection gas apportionment across multiple reservoirs is key to the overall value maximization in this complex development.

Maximum Reservoir Contact wells (MRCs) are a potential alternative to reduce the number of wells required to develop hydrocarbon reservoirs, improve sweeping efficiency and delay gas and water breakthrough. The well completions design is critical for the success of MRCs. In this study we present a case study of a MRC well completion design using Limited Entry Liners (LEL) in a mature carbonate reservoir under water and miscible gas injection. We developed an integrated workflow that considered a high-resolution numerical simulation model calibrated to static and dynamic data and wellbore-reservoir models coupling, for capturing the details of the flow interaction between both systems. Flow restrictions in the form of additional pressure drops to the flow from the reservoir into the wellbore were used to simulate the effect of small open flow areas, i.e.shot densities, in the LELs. Our work allowed identifying the most likely entry points of gas and water and design the well to minimize their impact on oil production. We observe that longer lengths open to flow outweighs the detrimental effect of producing from intervals closer to the water saturated zones. We also observed that balancing the inflow profile along the wellbore did not report beneficial results to oil production as it stimulates production from the reservoir zone from which the gas breakthrough is expected (middle of the producing section); this result is particularly relevant as it shows that designing the well completions with base only on static data could lead to poor production performance. The suggested completion for the MRC well encompasses four segments; a segment covering almost 50 % of the well length and located at the middle of the producing section with a blind liner (close to flow for gas control) and the remaining three with slotted liners with enough open area as to avoid causing significant pressure drops.

Southern Oman has several high pressure (500-1000 bar), deep (3-5 km) and critically sour oil fields (H2S/CO2 up to ~10%/25%). Most of these reservoirs are carbonate stringers encapsulated in salt lacking any natural aquifer support. Field Development strategy for most of the reservoirs in the cluster is primary depletion followed by miscible gas injection. No artificial lift mechanism is installed in these fields, as gas flood is expected to provide the necessary energy later. Many of these fields are depleted and reached lift-die out conditions due to high backpressure from the station. To extend the depletion production life, the team came with Low-Pressure Operation (LPO) project for these fields. This concept was successfully implemented in various fields across the 3 production stations in the cluster. LPO concept is a novel, pragmatic and cost-effective solution to continue production from previous lift die-out wells which is first of its kind in the company. This approach helped to utilize the existing infrastructure and ullage available in the facilities and eliminate the need for installing expensive and complex artificial lifts (e.g. ESP) or depletion compressor systems. This resulted in incremental production at very low UTC and low CAPEX requirements during the low oil price period.

The hydrocarbon gas huff and puff (HnP) technique has been used to improve oil production in unconventional oil reservoirs where excess capacity of produced gas is available and hydrocarbon prices are in a range to result in an economically viable case. Eagle Ford (EF) is one of the largest unconventional oil plays in the United State where HnP has been applied for enhanced oil recovery (EOR) at reservoirs within various oil windows. Our previously published Huff-n-puff results on dead oil with produced gas from Eagle Ford (EF) showed the recovery factor of hydrocarbon varying from 40 to 58%. The objective of this paper is to extend the experiments to live oil with EF core plugs to investigate the mechanisms of HnP which are affected by the composition of injected gas and resident oil, injection and soaking time as well as injection/depletion pressure gradient. Eagle Ford live oil and natural gas produced from the target area were used for HnP tests. Four representative core plugs were used with the tests conducted at reservoir conditions (125 °C and 3,500 psi). The live oil experiments with four reservoir core plugs showed an improvement in oil recovery with recovery factor (RF) varying from 19.5 to 33 % in six cycles of HnP, whereas the primary depletion on the same core plug showed RF below 11 %. A lower recovery factor of HnP from live oil saturated core in this study was observed as compared to dead oil saturated core reported in a previous publication. It is attributed to a lesser diffusion effect on mass transfer between injected gas and resident oil when the core is saturated with live oil. This behavior is displayed by the pressure decline curve during the first soaking period. A sharper diffusion pressure decline occurred in the dead oil saturated core plug where a higher concentration gradient between injected gas and resident oil drives a faster gas transport into the oil due to the molecular diffusion during the soaking period.

Miscible CO2 flood is a well-established proven EOR recovery mechanism. There have been a large number of CO2 EOR developments worldwide, in both carbonate and clastic reservoirs. Potential control or influence factors on incremental production and incremental recovery over water flood are well documented in the published literature. Some of the published CO2 EOR developments have reported relatively high incremental recoveries. ADNOC is a leader in miscible gas injection EOR in carbonate reservoirs. There are a number of ongoing miscible gas injection EOR developments within its portfolio contributing a significant amount of production. Miscible CO2 flood is a key EOR development for ADNOC. Following intensive screening studies and laboratory experiments, the first CO2 EOR pilot in the MENA region was conducted as early as 2009 in one of ADNOC Onshore fields. This paved the way for further large-scale deployment and CO2 WAG pilots starting in 2016, both onshore. Appreciable progresses have been made since 2009. This bodes well with the significant initiatives undertaken by the UAE towards carbon emissions and greenhouse gas reduction, climate control and sustainable development. There are broad consensus that climate changes are now and will continue to affect all countries on all continents. Potential global warming can disrupt national economies and adversely impact on lives, costing people, communities and countries already today and perhaps more in the future. Carbon Capture, Utilization, and Storage (CCUS) technologies have been making headlines and attracting increasing amount of renewed attention, because they are in line with meeting global greenhouse gas reduction goals, and contributing towards climate control and sustainable development. The giant Abu Dhabi onshore field consists of 6 carbonate reservoirs. Several pilots, immiscible hydrocarbon gas injection and CO2 WAG, and a pattern immiscible gas injection WAG flood have been executed. Miscible gas injection EOR is therefore field proven. However, due to large field size, surface congestion constraints, geological and fluid variations, miscible gas injection EOR development by reservoir individually becomes complex and economically challenging. This paper presents a comprehensive study and recommends an integrated CCUS Hub development approach - enabling field-wide EOR development with several hundred million-barrels of incremental recovery. The study follows a step-by-step systematic method. Existing water flood performances were assessed first. History matched full field simulation then leads to identification of CO2 EOR targets by area/flank for each reservoir. These are referred to as sweet development areas. Available advanced PVT data were analysed and a multi-reservoir single equation of state developed. It has been found that only CO2 is miscible across all six reservoirs, while hydrocarbon gas is also miscible for the deepest two reservoirs. Dedicated fine scale sector models (EOR history matched where applicable) were developed to generate multiple CO2 EOR development scenarios, for example, depending on water flood maturity at the time of CO2 EOR start-up, and potential impact on incremental oil production, incremental oil recovery due to reservoir heterogeneity. First results from sector modelling show that quite a few areas/flanks would be sub-economical if CO2 EOR development on a stand-alone basis. Hence the concept of a CCUS Hub is proposed, which would allow sweet development areas in any or all of the six reservoirs to be developed from a single common surface Cluster. There is potential space for development phasing, allowing additional CO2 EOR developments within the same cluster area once ullage and CO2 supply becomes available. The CCUS Hub development approach facilitates optimization and sharing of injection/production flow-lines; surface space, gathering and processing facilities, CO2 supply, CO2 recovery unit deployment coupled with produced gas re-injection into the 2 deepest reservoirs. Compared to a more conventional development approach of reservoir by reservoir, considerable scope for CAPEX and OPEX savings was found. Assuming a constant future oil price, a reduction in development costs would allow more sweet development areas to pass the threshold of economical development, leading to an increase in overall incremental production and recovery from CO2 EOR.

The gas compressibility factor is an important property in reservoir simulation studies. It is directly linked to the gas formation volume factor and the gas density thereby impacting wellhead injection pressure, reservoir voidage, injectivity, as well as the tendency for gas gravity override to occur in the reservoir. ADNOC's PVT database contains experiments on almost 2,000 samples, of which more than 100 have been subject to advanced gas injection experiments. Z-factor data have been compiled from the liberated gas during DV experiments as well as from CCE experiments on reservoir gases, injection gases, and swollen fluid mixtures. Several of these mixtures are very rich in H 2 S, whereas pressure and temperature are in the range of 14.7-14,500 psia and 80-365 °F, respectively. We test several different methods for predicting the Z-factor, such as the industry-standard Hall-Yarborough method, in combination with various models for pseudo-critical pressure and temperature and including correction for non-hydrocarbon components. Other methods tested include the GERG-2008 model, considered to be state-of-the-art for predicting physical properties for well-described gas mixtures, as well as the well-known Peng-Robinson cubic equation of state. Based on close to 10,000 data points in our database, the GERG-2008 model typically predicts the Z-factor to be within 2% of the measured value, which is on par with the experimental uncertainty. However, for some rich gas condensate mixtures, the model gives larger errors because its parameters are only tuned to compositions with components up to C 10 . This is to our knowledge the first time that the GERG-2008 EOS has been compared to standard Z-factor correlations for such a large number of data points. If compositional information is available, we recommend using either the GERG-2008 model or the Hall-Yarborough model with pseudo-critical properties provided by Kay (1936) . When compositions are not available, we find that the Standing correlation is more accurate than the Sutton model, also for sour mixtures.

This paper presents an integrated subsurface study that focuses on delivering field development planning of two reservoirs via comprehensive reservoir characterization workflows. The upper gas reservoir and lower oil reservoir are in communication across a major fault in the crest area of the structure. Gas from the upper reservoir, which is not under development, is being produced along with some oil producers from the oil reservoir as per acquired surveillance data. Pressure depletion is observed in observer wells of the upper reservoir, which substantiate both reservoirs communication. The oil reservoir is on production since 1994, under miscible hydrocarbon water alternating gas injection (HCWAG) and carbon dioxide (CO2) injection. The currently implemented development plan has been facing several complexities and challenges including, but not limited to, maintaining miscibility conditions, sustainability of production and injection in view of reservoirs communication, reservoir modeling challenges, suitability of monitoring strategy, associated operating costs and expansion of field development in newly appraised areas. In this study, an assessment of multiple alternative field development scenarios was conducted; with an aim to tackle field management and reservoir challenges. It commenced by a comprehensive synthesis of seismic, petrophysical (including extensive core characterizations), geological, production and reservoir engineering data to ensure data adequacy and effectiveness for development planning. The process was followed by evaluation of the historical reservoir management, HCWAG and CO2 injection practices using advanced analytics to identify areas for improvement and accelerate decision making process. The identified areas of improvement were incorporated into a dynamic model via diverse set of field management logics to screen wide range of scenarios. In the final step, the optimal scenarios were selected, in line of having strong economic indicators, honoring operational constraints, corporate business plan and strategic objectives. The comprehensive and flexible field management logic was set up to target different challenges and was used to extensively screen hundreds of different field development scenarios varying several parameters. Examples of such parameters are WAG ratio, injection pressures for both water/gas and CO2, cycle duration, well placement, reservoir production and injection guidelines, different co-development production schemes coupled with static and dynamic uncertainty properties against incremental oil production and discounted cash flow. The simulation results were analyzed using standardized approach where a number of key indicators was cross-referenced to produce optimal field development scenarios with regards to co-development effect of both reservoirs, miscibility conditions, balanced pressure depletion, harmonized sweep as well as robust discounted cash flow. Strong management support, multi-disciplinary data integration, agility of decision making and revisions in a controlled timeframe are considered as the key pillars for success of this study. The adopted workflow covers subsurface modeling aspects from A-Z and following reservoir characterization and modeling best practices. The methodology applied in this study uses an integrated subsurface structured approach to tackle reservoirs challenges and co-development, generate alternative development options leveraging on data analytics techniques and advanced field management strategies.

The objective of this paper is to investigate the water and gas injectivity in water alternating gas (WAG) projects using laboratory and field scale data. It has been reported in the literature that both gas and water mobility has been significantly reduced in three-phase flow compared to two-phase flow. This behaviour has been attributed to a cycle dependent hysteresis effect which reduced both gas and water mobility in the different injection cycles. To address the gas and water injectivity and the cycle dependent hysteresis concept, the results of a detailed experimental program in addition to field injectivity data will be presented. The experimental program included three-phase experiments performed under reservoir conditions using live crude oil and carbonate reservoir core material. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir conditions and CO 2 was used as miscible injectant. The field injectivity data is obtained from two CO 2 WAG pilots in a carbonate reservoir. The main conclusions of the study are: 1- Gas injectivity in the presence of mobile water is much lower than that in the absence of water, 2- Water injectivity in experiments starting with water cycle is better than that in experiments starting with gas cycle when compared at the same water saturation, 3- Cyclic hysteresis in gas relative permeability was observed when comparing the first and second gas cycle, however, no further hysteresis was observed in the subsequent gas injection cycles, 4- Cyclic hysteresis in water relative permeability was not observed, the injectivity was either the same or higher in the subsequent cycles. 5- The gas injectivity at similar gas saturation for experiments starting with gas is better than that for experiments starting with water, 6- Gas and water injectivity field data from ongoing CO 2 WAG projects in carbonate reservoirs showed no cyclic hysteresis, the injectivity either the same or improved in the subsequent cycles, 7- The CO 2 injectivity was lower than expected, in the same order as water injectivity, which could be due to injecting CO 2 in high water saturation zone and 8) The low CO 2 injectivity could have a positive impact on sweep efficiency and potential improvement of oil recovery. This paper presents the results of a well-designed experimental program and field data from two CO 2 WAG pilots to systematically investigate water and gas injectivity in miscible WAG projects in carbonate reservoirs. The paper provides a rich and rarely available set of experimental and field data that can help improve and optimize gas and WAG injection projects in carbonate reservoirs. Detailed analysis of the field gas and water injectivity data will be presented and discussed in-light of the laboratory experimental data.