Numerical modeling of self-potential in heterogeneous reservoirs

Monitoring water movement toward production wells through downhole measurements of self-potential (SP) was a promising new technology. However, there were uncertainties about its applicability in heterogeneous, multilayered reservoirs. Using numerical modeling, we investigated the likely magnitude and behavior of SP during oil production supported by water injection in two different models of such reservoirs. We found that the magnitude of the SP signal that would be measured along a production well increased as water approached the well, exceeding an assumed noise level of 0.1 mV before water breakthrough. We also found that, in the reservoir models tested, the maximum value of SP at the well skewed toward the fastest waterfront before water breakthrough. The trend of SP increasing at the well with time, together with the shape of the SP profile, were the prime indicators used to investigate water movement. In the reservoir models tested, before water breakthrough the fastest approaching waterfront could be detected approximately 20 m away from the well. However, subsequent waterfronts approaching the well in other layers could not be detected before breakthrough. The effect of these later waterfronts on the SP profile at the well was only detectable at breakthrough. We attributed this to the fact that the SP generated in these layers is masked by the high SP created by the fastest waterfront. Our findings emphasized the importance of an enhanced understanding of reservoir geology and rock electrical properties for better prediction and interpretation of SP.

Numerical simulation and optimization of CO2 enhanced gas recovery in homogeneous and vertical heterogeneous reservoir models

CO2 enhanced gas recovery (CO2-EGR) is a promising, environment-friendly technology with simultaneously sequestering CO2. The goals of this paper are to conduct simulations of CO2-EGR in both homogeneous and heterogeneous reservoirs to evaluate effects of gravity and reservoir heterogeneity, and to determine optimal CO2 injection time and injection rate for achieving better natural gas recovery by employing a genetic algorithm integrated with TOUGH2. The results show that gravity segregation retards upward migration of CO2 and promotes horizontal displacement efficiency, and the layers with low permeability in heterogeneous reservoir hinder the upward migration of CO2. The optimal injection time is determined as the depleted stage, and the corresponding injection rate is optimized. The optimal recovery factors are 62.83 % and 64.75 % in the homogeneous and heterogeneous reservoirs (804.76 m × 804.76 m × 45.72 m), enhancing production by 22.32 × 103 and 23.00 × 103 t of natural gas and storing 75.60 × 103 and 72.40 × 103 t CO2 with storage efficiencies of 70.55 % and 67.56 %, respectively. The cost/benefit analysis show that economic income of about 8.67 and 8.95 million USD can be obtained by CO2-EGR with optimized injection parameters respectively. This work could assist in determining optimal injection strategy and economic benefits for industrial scale gas reservoirs.

Paradigm Shift from Cemented Completions to Multi-Stage Completion Strategy for Managing Tight Gas Development Challenges

The development of North Kuwait Jurassic gas assets has strategic importance for Kuwait's production strategy as the only non-associated gas-producing field in Kuwait. This paper demonstrates the benefits, challenges and lessons learned of the recent paradigm shift in Jurassic tight gas wells’ completion strategy from cemented liner to multi-stage completion. Successful expansion of Multi-Stage Completion (MSC) technology is achieved at the field level led by the integrated team efforts in 2020/21, despite challenging constraints of COVID-19. MSC's help to enhance overall well production potential, overcome reservoir and intervention operation challenges, and allow early production delivery, which is a key factor to achieve a strategic asset production target of 70-80% by 2024/25. Many technical and logistic challenges were experienced during first installations of which the relevant learnings will be shared in this paper. The Jurassic gas asset produces mainly from deep high pressure and temperature, conventional and unconventional tight carbonate reservoirs. The recovery from such complex heterogeneous reservoirs is extremely challenging if conventional development strategies are applied. Therefore, a dedicated full development plan applying integrated upstream and downstream technologies is important to achieve the strategic production target. Due to the excessive Jurassic carbonate reservoir tightness, permeability contrast and dual permeability effect (matrix and natural fractures), well productivity potential significantly depends on the effectiveness of subsequent stimulation treatments of such complex heterogeneous reservoirs to improve well productivity and potentially connect with natural fractures. Selecting proper well completion design is critical to overcome such reservoir challenges and ensure effective acid stimulation treatments for the mix of conventional and unconventional formations that need convenient diversion mechanism during stimulation to enhance the productivity of each individual reservoir flow unit and enable selective future flexibility of re-stimulation and reservoir management. The asset team has recently applied a step change in completion strategy to open hole multi-stage ball drop completions using state of the art MSC technologies including closeable frac sleeves, full 3.5-in monobore ID post frac sleeves milling and debris sub enclosure to protect the MSC string during casing tie-back operations. This is to overcome reservoir complexity, eliminate wellbore cleaning and decrease the challenges and risks that accompany multiple perforation intervention operations. As well as, eliminate cement quality risks and uncertainties, improve overall cost, and fast track well delivery to production to meet asset production targets by significantly reducing operation time from approximately one month for plug and perf techniques to less than one week when using continuous and less subsurface intervention operations. Recently, a total of 13 new MSC installations and subsequent multi-stage stimulations were achieved in seven months, fromQ3-2020 to Q1-2021, with positive overall production results, significant improvement of intervention operation efficiency and faster well delivery to production. This paper will describe the details of progress to date, and the plan forward for optimization and new technology trials to further improve well performance.

The impact of permeability heterogeneity on water-alternating-gas displacement in highly stratified heterogeneous reservoirs

Availability of gases at the field level makes attractive to water-alternating-gas (WAG) process for low viscosity and light oils carbonate reservoir. However, impact of reservoir heterogeneity on WAG performance is crucial before field application. In general, ramp carbonates have heterogeneity due to variation of permeability and porosity. However, WAG performance significantly affected by permeability variations. This article investigates merits and demerits of WAG displacement due to permeability heterogeneities such as permeability anisotropy, high permeability streaks (HKS), matrix permeability, dolomite and thin dense stylolite layers. High-resolution compositional simulations with tuned equation of state (EoS) were carried out using 2D and 3D sector models. The study focuses on WAG performance in terms of oil recovery, vertical sweep, solvent utilization, gas oil ratio (GOR), water cut (WCT), WAG response time, gravity override, hysteresis, un-contacted oil saturation and economics. The results of simulation show that the heterogeneous reservoir provides initially faster WAG response, lower expected ultimate recovery (EUR), faster gas breakthrough, higher GOR and WCT production compared to homogeneous reservoir. The gas gravity override at smaller wells spacing is less in homogeneous reservoir as compared to heterogeneous reservoir, but it is reverse in case of larger well spacing. In heterogeneous reservoir, the HKS shows significant gas override resulting in poor vertical sweep due to capillary holding, and the high permeability dolomite layer shows early water breakthrough. This reservoir has higher solvent utilization in initial stage, and then, it becomes nearly equal to homogeneous reservoir. Simulation in both reservoirs overestimates incremental recovery of 2–3% OOIP at one pore volume injection because of not involving un-contacted oil saturation as predicted in core flood. The findings of this study will help to understand WAG performance and design in highly heterogeneous reservoirs for field applications. Graphical abstract

From Completion Design to Efficiency Analysis of Inflow Control Device: Comprehensive Approach for AICD Implementation for Thin Oil Rim Field Development Efficiency Improvement

The complex interbedded heterogeneous reservoirs of the Severo-Komsomolskoye field are developed by horizontal wells in which, as part of the pilot project's scope, autonomous inflow control devices (AICD) are installed to prevent early coning and gas breakthroughs in long horizontal sections and reduce sand production, which is a problem aggravated by an extremely low mechanical strength of the terrigenous deposits occurring in the Pokur formation of the Cenomanian stage in this area. The zones produced through AICDs are separated by swell packers. The issue of AICD effectiveness is discussed in the publications by Solovyev (2019), Shestov (2015), Byakov (2019) and some others. One of the methods used for monitoring horizontal sections with AICDs is production logging (PLT). However, due to the complexity of logging objectives, the use of conventional logging techniques makes the PLT unfeasible, considering the costs of preparing and carrying out the downhole operations. This paper provides some case studies of the Through-Barrier Diagnostics application, including passive spectral acoustics (spectral acoustic logging) and thermohydrodynamic modelling for the purpose of effective estimation of reservoir flows behind the liner with AICDs installed and well integrity diagnostics. As a result of the performed diagnostics, the well completion strategy was updated and optimised according to the log interpretation results, and one well intervention involving a cement squeeze with a straddle-packer assembly was carried out.