Gas injection is a proven enhanced oil recovery method, especially for light oil reservoirs. The primary objective of gas injection is to improve the displacement efficiency and reduce residual oil saturation below the values usually obtained in waterflooding. However, the macroscopic sweep efficiency of gas injection can be suboptimal, mainly due to channelling, viscous fingering and gravity segregation of the injected gas. The macroscopic sweep of gas injection is further reduced for highly heterogeneous reservoirs. In this paper we examine the ability of both foam and polymer to provide mobility control to gas injection in a mixed-wet carbonate reservoir with high permeability contrast, i.e, high permeability zone on top of a low permeability zone. Under waterflood, there is an impediment for water to flow from the high permeable Upper zone to the Lower zone due to e.g., capillary pressure. The paper presents two new emerging technologies for mobility control of gas injection, which results in improving vertical sweep efficiency of oil reservoirs, namely: 1-SIMGAP: Simultaneous injection of miscible gas in the low permeable Lower zone and a polymer solution in the high permeable Upper zone. A lateral pressure gradient is maintained in the Upper zone by the injected polymer, providing Lower zone gas confinement; and2-Foam: Simultaneous injection of surfactant solution in the Upper zone and gas in the Lower zone. As gas migrates to the Upper zone, foam will be created in-situ and reduces both gas and water mobility in the Upper zone. This leads to the containment of the gas in the Lower zone, thus improving vertical sweep of the reservoir. The EOR processes are compared based on recovery factor, possibility of success, robustness to geological heterogeneity and operating conditions and stability at high temperature and salinity conditions. Simulation results show that the two EOR processes have the potential of recovering the oil that is by-passed by waterflood or conventional gas injection schemes. The SIMGAP process (polymer based) leads to higher recovery factor than the foam process. Experimental data supporting simulation work was also conducted as part of this study.

Enhanced oil recovery (EOR) has become increasingly important to maintain and extend the production plateaus of existing oil reservoirs. Simulation models for EOR studies require the right level of spatial resolution to capture reservoir heterogeneity. Data acquired from the dedicated observation wells are essential in defining the required resolution to capture reservoir heterogeneity. For giant reservoirs with long production history, their full field models usually have grid block sizes that are of similar scale as the distance between injectors and observation wells, with the consequence of losing the value of the time lapse saturation logs from dedicated observation wells. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must.The objective of this paper is to present an improved and integrated reservoir characterization, modelling and water and gas injection history matching procedure of a giant Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates geological, petrophysical, and dynamic data in order to understand the production history and the remaining oil saturation distribution in the reservoir. Large amounts of field data, including time lapse saturation logs from observation wells, have been collected over the last decades to provide insight into the sweep efficiency and flow paths of the injected water.Iterative simulations were performed to investigate different scenarios and various sensitivities with each iteration involving an update of the static model to honor both the dynamic and core/log data. While applying this iterative process it was also acknowledged that conventional core data (e.g. 1 plug per foot) may not capture the high permeability streaks in these heterogeneous reservoirs that control much of the reservoir flow behaviour, hence much denser plugging and core examination is required. In addition, permeability upscaling procedures need to take into account the fact that core plugs may not represent the effective permeability of the larger connected vuggy pore systems.The improved understanding of reservoir heterogeneity, the more robust reservoir characterization, and the improved history matching demonstrates that a better representation of reservoir dynamics is achieved. This provides a solid platform for designing and planning future EOR schemes.

Carbonate reservoirs in the Middle East are highly heterogeneous with complex porosity systems and mixed-wet matrix properties. These characteristics strongly affect reservoir performance under waterflooding. This paper concerns a highly layered limestone reservoir with various levels of cyclicity in properties and can be described at a high level as consisting of two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under waterflooding. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this paper we will investigate different development options for such heterogeneous mixed-wet reservoirs aiming at improving recovery from the Lower zone: 1- Optimized waterflooding with infill wells, 2- Novel EOR options designed to overcome the capillary forces and improve vertical sweep. The EOR options include (a) polymer-assisted solutions consisting of injecting polymer in the Upper zone and water or miscible gas in the Lower zone; and (b) surfactant assisted solutions (foam and enhanced gravity drainage). The main conclusions of the study are: 1- Waterflooding is an efficient recovery mechanism for the Upper zone and tight well spacing is required to improve recovery from the Lower zone; 2- The EOR processes have the potential of improving recovery from the Lower zone; 3- The most attractive EOR schemes are the polymer-based options which, when compared to the optimized waterflooding/infill scenario, lead to much higher recovery, lower volumes of water injected and significantly less water cycling and the requirement of fewer wells. The polymer-assisted solutions also require injecting much lower polymer volumes compared to conventional polymer flooding. Simulation results show that the process(es) are robust to injection rates, vertical heterogeneity, well completions and a range of polymer viscosities.

High Pressure Air Injection (HPAI) is a potentially attractive enhanced oil recovery method for deep, high-pressure light oil reservoirs after waterflooding. The advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas, is its availability at any location. HPAI has been successfully applied in the Williston Basin for more than twenty years and is currently being considered by many operators for application in their assets.Evaluation of the applicability of HPAI requires conducting laboratory experiments under reservoir temperature and pressure conditions to confirm crude auto-ignition and to assess the burn characteristics of the crude/reservoir rock system. The ensuing estimation of the potential incremental recovery from the application of HPAI in the reservoir under consideration requires fit-for-purpose numerical modeling. Typically, the flue gas generated in-situ by combustion leads to in an immiscible gas drive, where the stripping of volatile components is a key recovery mechanism. HPAI has therefore, in some instances, been modeled as an isothermal flue gas drive, employing an Equation of State (EOS) methodology. This approach, however, neglects combustion and its effects on both displacement and sweep. Furthermore, the EOS approach cannot predict if, and when, oxygen breakthrough at producers occurs. Combustion can be included in a limited fashion in simulations at the expense of extra computational time and complexity. In the available literature, combustion is taken generally into account under quite simplified conditions. This paper addresses the role that combustion plays on the incremental recovery of HPAI. Numerical simulations were conducted in a 3D model with real geological features. In order to capture more realistically the physics of the combustion front, a reservoir simulator with dynamic gridding capabilities was used. Kinetic parameters were based on the combustion tube laboratory experiments. The impact of combustion on residual oil, sweep efficiency and predicted project lifetime is presented by comparing isothermal EOS-simulations and multi-component combustion runs.

This paper presents a method for improving oil recovery from heterogeneous mixed to oil-wet carbonate reservoirs. In reservoirs where a high-permeability zone is above a low permeability zone, under water flooding the injected water tends to flow through the upper zone along the high permeability layers with no or very slow cross flow of water into the lower zone, resulting in very poor sweep of the lower zone. It has been demonstrated in earlier publications that this water override phenomenon is caused by capillary forces which act as a vertical barrier and counteracts gravity force in cases where permeability varies between layers for mixed to oil-wet reservoirs. There is significant scope for improving oil recovery from such type of heterogeneous mixed to oil-wet carbonate reservoirs. Gas injection is known to improve displacement efficiency by reducing residual oil saturation. However, for reservoirs of high permeability contrast especially when the high permeable layers are in the upper part of the reservoir, conventional gas injection (immiscible or miscible) becomes less effective because of gravity override and/or viscous fingering caused by unfavourable mobility ratio compounded by geological heterogeneity. The main challenge to gas injection in such reservoirs is to confine the gas into the low permeability zones and improve sweep efficiency. Therefore, for this type of carbonate reservoirs, mobility control is required to enable gas/CO2 EOR due to the geological heterogeneity and gravity override. This paper presents a new EOR scheme where mobility control of the injected gas is achieved by injecting viscosified water into the upper zone while injecting miscible gas into the lower zone using vertical and/or horizontal wells. A key prerequisite is to have a static model that captures the geological heterogeneity (e.g., vertical permeability contrast, all prevailing rock types) and a dynamic model that incorporates the SCAL derived capillary pressure (both drainage and imbibition) and relative permeability curves. Integrated geological, petrophysical and reservoir engineering effort was devoted to this EOR program that led to history matched sector models which honours the waterflood remaining oil saturation distribution shown in cased hole time-lapse saturation logs. The model forecasts show that significant sweep of the lower zone is achieved compared to both water or gas injection and that the process is stable and robust to reservoir lateral and vertical heterogeneity. This EOR process has the potential of recovering the oil that is by-passed by waterflood or conventional gas injection schemes. It is particularly suited for layered oil reservoirs where there is an impediment for water to flow from the upper high permeable zone to the lower reservoir due to e.g. (vertical) permeability reduction at the interface or a capillary pressure barrier. It is also applicable for improving oil recovery from the low permeable layers inter-bedded within the more permeable reservoir unit. Additional benefit of this process is to potentially enable economic EOR and CO2 storage in such kind of heterogeneous reservoirs.

The limited-memory Broyden–Fletcher–Goldfarb–Shanno (L-BFGS) optimization method performs very efficiently for large-scale problems. A trust region search method generally performs more efficiently and robustly than a line search method, especially when the gradient of the objective function cannot be accurately evaluated. The computational cost of an L-BFGS trust region subproblem (TRS) solver depend mainly on the number of unknown variables (n) and the number of variable shift vectors and gradient change vectors (m) used for Hessian updating, with m << n for large-scale problems. In this paper, we analyze the performances of different methods to solve the L-BFGS TRS. The first method is the direct method using the Newton-Raphson (DNR) method and Cholesky factorization of a dense n × n matrix, the second one is the direct method based on an inverse quadratic (DIQ) interpolation, and the third one is a new method that combines the matrix inversion lemma (MIL) with an approach to update associated matrices and vectors. The MIL approach is applied to reduce the dimension of the original problem with n variables to a new problem with m variables. Instead of directly using expensive matrix-matrix and matrix-vector multiplications to solve the L-BFGS TRS, a more efficient approach is employed to update matrices and vectors iteratively. The L-BFGS TRS solver using the MIL method performs more efficiently than using the DNR method or DIQ method. Testing on a representative suite of problems indicates that the new method can converge to optimal solutions comparable to those obtained using the DNR or DIQ method. Its computational cost represents only a modest overhead over the well-known L-BFGS line-search method but delivers improved stability in the presence of inaccurate gradients. When compared to the solver using the DNR or DIQ method, the new TRS solver can reduce computational cost by a factor proportional to n2/m for large-scale problems.

A new EOR scheme is proposed to improve sweep efficiency and oil recovery from heterogeneous mixed to oil-wet carbonate reservoirs. The reservoir under study is a highly heterogeneous and layered reservoir which can be described at a high level as consisting of two main bodies, i.e., an Upper zone and a Lower zone with a permeability contrast of up to a factor of 100.The main recovery mechanism currently applied is water flooding. Field data shows that injected water tends to travel quickly through the Upper zone along the high permeability layers and bypasses the low permeable Lower zone, which results in poor sweep of the Lower zone. It has been demonstrated in earlier publications that this water override phenomenon is caused by capillary forces which act as a vertical barrier and counteract gravity for mixed or oil-wet reservoirs.Polymer flooding has been proposed to improve sweep efficiency in heterogeneous reservoirs. In this paper we propose a new polymer based EOR option in which the water and polymer are injected simultaneously into the Lower and Upper zones, respectively. Injection of polymer into Upper zone serves to minimize cross-flow of injected water from the Lower zone and improves the sweep efficiency of both Upper and Lower zones. Compared to polymer injection alone, a much lower volume of polymer is required which has a significant positive impact on cost of this EOR process.Numerical simulations have been performed using a history matched sector model. The model forecasts show that significant sweep improvement of the Lower zone is achieved compared to conventional water or gas injection. The results also show that the process is stable and robust to reservoir lateral and vertical heterogeneity, variation in polymer viscosity and that the amount of polymer that is used can be limited by only injecting a polymer slug of 0.1 to 0.2 pore volume. It is also shown that the process can be implemented in secondary and tertiary mode, where in tertiary mode earlier handling of production water is required. Experimental work shows there are promising polymers that may be able to withstand the high reservoir temperature, high salinity and high concentration of divalent ions in the reservoir under study. Problem Statement: Impact of Heterogeneity and Capillary Forces on Oil RecoveryReservoir heterogeneity has an important effect on waterflood performance, especially for layered mixed or oil-wet reservoirs. For such reservoirs, one of the important factors that affect fluid flow is the cross-flow of fluids form one layer into another in the direction perpendicular to the main flow path. It is well recognized that cross-flow has significant impact on sweep efficiency of immiscible displacement in layered reservoirs. The effect of both gravity and viscous forces on cross-flow and sweep efficiency has been extensively studied in the literature (Root and Skiba 1964, Goddin et. al. 1966, Yakoyama and Lake 1981, Zapata and Lake 1981, Tompang and Kelkar 1988, Fitzmorris et. al. 1992, Angert et. al. 1993. In most ...

Petroleum Development Oman's (PDO) portfolio of heavy-oil, fractured carbonate prospects and fields contains a potentially large number of EOR opportunities, many of which present unique subsurface challenges. In the context of evaluating one such field, an EOR screening approach was developed combining subsurface definition through a tailor-made appraisal campaign, coupled with technical & economic feasibility evaluation of candidate EOR methods and benchmarking against other fields globally. This paper presents the screening workflow that will serve as template for the evaluation of future EOR opportunities in heavy-oil, fractured carbonate discoveries in PDO.At the outset of the reservoir characterization of this field it was recognized that the application of any EOR technique would be challenging. High oil viscosities coupled with shallow depths render it a candidate for thermal EOR and potentially chemical concepts. However, key uncertainties in basic subsurface parameters such as reservoir architecture, matrix permeability, fracture spacing and (low) oil saturations, necessitated further data gathering before feasibility of any recovery mechanism could be concluded.Based on literature surveys and examination of showstopper properties, a first-pass screening of a multitude of thermal and chemical EOR methods was conducted. A probabilistic assessment of key subsurface parameters was conducted against which the candidate EOR techniques were ranked. This resulted in the identification of SAGOGD, CSS, ISC and novel-chemical flooding as the most promising EOR methods.For each of these methods the critical subsurface parameters and their impact were further assessed through the combination of (1) an appraisal campaign that included drilling of new wells, conventional production & pressure interference testing to constrain the uncertainties in these parameters and (2) Fit-for-purpose modeling (analytical analysis, sector modeling and full-field simulation) to check project feasibility.It was found that none of the thermal recovery methods are technically or economically feasible, but chemical methods are being investigated further. 2 SPE 155546