scholarly journals MODEL-BASED OPTIMIZATION OF CYCLES OF CO2 WATER-ALTERNATING-GAS (CO2-WAG) INJECTION IN CARBONATE RESERVOIR

2022 ◽  
Vol 15 (4) ◽  
pp. 139-149
Author(s):  
F. G. A. Pereira ◽  
V. E. Botechia ◽  
D. J. Schiozer
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Co2 Production ◽  
Co2 Injection ◽  
Optimal Size ◽  
Control Variables ◽  
Limit Values ◽  
Water Alternating Gas ◽  
Production Wells ◽  
The Impact

Pre-salt reservoirs are among the most important discoveries in recent decades due to the large quantities of oil in them. However, high levels of uncertainties related to its large gas/CO2 production prompt a more complex gas/CO2 management, including the use of alternating water and gas/CO2 injection (WAG) as a recovery mechanism to increase oil recovery from the field. The purpose of this work is to develop a methodology to manage cycle sizes of the WAG/CO2, and analyze the impact of other variables related to the management of producing wells during the process. The methodology was applied to a benchmark synthetic reservoir model with pre-salt characteristics. We used five approaches to evaluate the optimum cycle size under study, also assessing the impact of the management of producing wells: (A) without closing producers due to gas-oil ratio (GOR) limit; (B) GOR limit fixed at a fixed value (1600 m³/m³) for all wells; (C) GOR limit optimized per well; (D) joint optimization between GOR limit values of producers and WAG cycles; and (E) optimization of the cycle size per injector well with an optimized GOR limit. The results showed that the optimum cycle size depends on the management of the producers. Leaving all production wells open until the end of the field's life (without closing based on the GOR limit) or controlling the wells in a more restricted manner (with closing based on the GOR limit), led to significant variation of the results (optimal size of the WAG/CO2 cycles). Our study, therefore, demonstrates that the optimum cycle size depends on other control variables and can change significantly due to these variables. This work presents a study that aimed to manage the WAG-CO2 injection cycle size by optimizing the life cycle control variables to obtain better economic performance within the premises already established, such as the total reinjection of gas/CO2 produced, also analyzing the impact of other variables (management of producing wells) along with the WAG-CO2 cycles.

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

2021 ◽  
Author(s):  
Mohammad Yunus Khan ◽  
Ajay Mandal
Keyword(s):  
Oil Recovery ◽  
Field Application ◽  
Carbonate Reservoir ◽  
High Permeability ◽  
Oil Saturation ◽  
Heterogeneous Reservoirs ◽  
Heterogeneous Reservoir ◽  
Low Viscosity ◽  
Water Alternating Gas ◽  
The Impact

AbstractAvailability 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

Experimental Investigation of Near-Miscible Water-Alternating-Gas Injection Performance in Water-Wet and Mixed-Wet Systems

SPE Journal ◽  
2013 ◽  
Vol 18 (01) ◽  
pp. 114-123 ◽  
Author(s):  
S. Mobeen Fatemi ◽  
Mehran Sohrabi
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Laboratory Data ◽  
Co2 Injection ◽  
Water Alternating Gas ◽  
Three Phase ◽  
The Impact ◽  
Wag Injection

Summary Laboratory data on water-alternating-gas (WAG) injection for non-water-wet systems are very limited, especially for near-miscible (very low IFT) gas/oil systems, which represent injection scenarios involving high-pressure hydrocarbon gas or CO2 injection. Simulation of these processes requires three-phase relative permeability (kr) data. Most of the existing three-phase relative permeability correlations have been developed for water-wet conditions. However, a majority of oil reservoirs are believed to be mixed-wet and, hence, prediction of the performance of WAG injection in these reservoirs is associated with significant uncertainties. Reliable simulation of WAG injection, therefore, requires improved relative permeability and hysteresis models validated by reliable measured data. In this paper, we report the results of a comprehensive series of coreflood experiments carried out in a core under natural water-wet conditions. These included water injection, gas injection, and also WAG injection. Then, to investigate the impact of wettability on the performance of these injection strategies, the wettability of the same core was changed to mixed-wet (by aging the core in an appropriate crude oil) and a similar set of experiments were performed in the mixed-wet core. WAG experiments under both wettability conditions started with water injection (I) followed by gas injection (D), and this cyclic injection of water and gas was repeated (IDIDID). The results show that in both the water-wet and mixed-wet cores, WAG injection performs better than water injection or gas injection alone. Changing the rock wettability from water-wet to mixed-wet significantly improves the performance of water injection. Under both wettability conditions (water-wet and mixed-wet), the breakthrough (BT) of the gas during gas injection happens sooner than the BT of water in water injection. Ultimate oil recovery by gas injection is considerably higher than that obtained by water injection in the water-wet system, while in the mixed-wet system, gas injection recovers considerably less oil.

Advances in Midland Basin Expand Boundaries of CO2 EOR in Marginal Pay Areas

2021 ◽  
Vol 73 (06) ◽  
pp. 65-66
Author(s):  
Judy Feder
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Improved Oil Recovery ◽  
Midland Basin ◽  
The North ◽  
Production Wells ◽  
Original Oil In Place ◽  
Carbon Dioxide Co2

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200460, “A Case Study of SACROC CO2 Flooding in Marginal Pay Regions: Improving Asset Performance,” by John Kalteyer, SPE, Kinder Morgan, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. As one of the first fields in the world to use carbon dioxide (CO2) in enhanced oil recovery (EOR), the Scurry Area Canyon Reef Operators Committee (SACROC) unit of the Kelly-Snyder field in the Midland Basin of Texas provides a unique opportunity to study, learn from, and improve upon the development of CO2 flood technology. The complete paper reviews the history of EOR at SACROC, discusses changes in theory over time, and provides a look at the field’s future. Field Overview and Development History The first six pages of the paper discuss the field’s location, geology, and development before June 2000, when Kinder Morgan acquired the SACROC unit and took over as operator. Between initial gas injection in 1972 and 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. Since 2000, cumulative CO2 injection has sur-passed 7 TCF and yielded cumulative EOR of over 180 million bbl. The reservoir is a primarily limestone reef complex containing an estimated original oil in place (OOIP) of just under 3 billion bbl. The reservoir ranges from 200 ft gross thickness in the south to 900 ft in the north, where the limestone matrix averages 8% porosity and 20-md permeability. The Canyon Reef structure is divided into four major intervals, of which the Upper Canyon zone provides the highest-quality pay. The field was discovered in 1948 at a pressure of 3,122 psi. By late 1950, 1,600 production wells had been drilled and the reservoir pressure plummeted, settling as low as 1,700 psi. Waterflooding begun in 1954 enabled the field to continue producing for nearly 20 years, at which time the operators deter-mined that another recovery mechanism would be needed to maximize recovery and reach additional areas of the field. The complete paper discusses various CO2 injection programs that were developed and applied—including a true tertiary response from a miscible CO2 flood in 1981—along with their outcomes. Acquisition and CO2-Injection Redevelopment In June 2000 Kinder Morgan acquired the SACROC Unit and took over as operator. Approximately 6.7 billion bbl of water and 1.3 TCF of CO2 had been injected across the unit to that date, but the daily oil rate of 8,700 B/D was approaching the field’s economic limit. An estimated 40% of the OOIP had been produced through the combination of recovery methods that each previous operator had used. Expanding on the conclusions of its immediate predecessor, the operator initiated large-scale CO2-flood redevelopment in a selection of project areas. These redevelopments were based on several key distinctions differentiating them from previous injection operations.

scholarly journals Oil recovery for fractured-vuggy carbonate reservoirs by cyclic water huff and puff: performance analysis and prediction

2019 ◽  
Vol 9 (1) ◽  
Author(s):  
Daigang Wang ◽  
Jingjing Sun
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
High Efficiency ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Production Performance ◽  
Quantitative Prediction ◽  
Attractive Alternative ◽  
Marquardt Algorithm ◽  
The Impact

Abstract Cyclic water huff and puff (CWHP) has proven to be an attractive alternative to improve oil production performance after depletion-drive recovery in fractured-vuggy carbonate reservoirs. However, due to the impact of strong heterogeneity, multiple types of fractured-vuggy medium, poor connectivity, complex flow behaviors and oil-water relationship, CWHP is merely suitable for specific types of natural fractured-vuggy medium, usually causing a great difference in actual oil-yielding effect. It remains a great challenge for accurate evaluation of CWHP adaptability and quantitative prediction of production performance in fractured-vuggy carbonate reservoir, which severely restricts the application of CWHP. For this study, we firstly enable the newly developed fuzzy grey relational analysis to quantify the adaptability of CWHP. With production history of several targeted producers, the accuracy of the proposed method is validated. Based on the traditional percolation theory and waterflood mechanisms in various types of fractured-vuggy medium, a quantitative prediction model for cyclic water cut fwp and increased recovery factor ΔR is presented. The CWHP production performance is discussed by using the Levenberg-Marquardt algorithm for history matching. With a better understanding of the fwp ~ ΔR curve characteristics in different types of fractured-vuggy medium, proper strategies or measures for potential-tapping remaining oil are provided. This methodology can also offer a good basis for engineers and geologists to develop other similar reservoirs with high efficiency.

scholarly journals CO2 Injection and Enhanced Oil Recovery in Ohio Oil Reservoirs—An Experimental Approach to Process Understanding

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6215
Author(s):  
Manoj Kumar Valluri ◽  
Jimin Zhou ◽  
Srikanta Mishra ◽  
Kishore Mohanty
Keyword(s):  
Oil Recovery ◽  
Power Plants ◽  
Oil And Gas ◽  
Oil Reservoirs ◽  
Reservoir Rock ◽  
Co2 Injection ◽  
Reservoir Properties ◽  
Industrial Facilities ◽  
Water Alternating Gas ◽  
Process Understanding

Process understanding of CO2 injection into a reservoir is a crucial step for planning a CO2 injection operation. CO2 injection was investigated for Ohio oil reservoirs which have access to abundant CO2 from local coal-fired power plants and industrial facilities. In a first of its kind study in Ohio, lab-scale core characterization and flooding experiments were conducted on two of Ohio’s most prolific oil and gas reservoirs—the Copper Ridge dolomite and Clinton sandstone. Reservoir properties such as porosity, permeability, capillary pressure, and oil–water relative permeability were measured prior to injecting CO2 under and above the minimum miscibility pressure (MMP) of the reservoir. These evaluations generated reservoir rock-fluid data that are essential for building reservoir models in addition to providing insights on injection below and above the MMP. Results suggested that the two Ohio reservoirs responded positively to CO2 injection and recovered additional oil. Copper Ridge reservoir’s incremental recovery ranged between 20% and 50% oil originally in place while that of Clinton sandstone ranged between 33% and 36% oil originally in place. It was also deduced that water-alternating-gas injection schemes can be detrimental to production from tight reservoirs such as the Clinton sandstone.

Effective Prediction and Management of a CO2 Flooding Process for Enhancing Oil Recovery Using Artificial Neural Networks

2017 ◽  
Vol 140 (3) ◽  
Author(s):  
Si Le Van ◽  
Bo Hyun Chon
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Environmental Benefits ◽  
Co2 Production ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Injection Process ◽  
Artificial Neural

The injection of CO2 has been in global use for enhanced oil recovery (EOR) as it can improve oil production in mature fields. It also has environmental benefits for reducing greenhouse carbon by permanently sequestrating CO2 (carbon capture and storage (CCS)) in reservoirs. As a part of numerical studies, this work proposed a novel application of an artificial neural network (ANN) to forecast the performance of a water-alternating-CO2 process and effectively manage the injected CO2 in a combined CCS–EOR project. Three targets including oil recovery, net CO2 storage, and cumulative gaseous CO2 production were quantitatively simulated by three separate ANN models for a series of injection frames of 5, 15, 25, and 35 cycles. The concurrent estimations of a sequence of outputs have shown a relevant application in scheduling the injection process based on the progressive profile of the targets. For a specific surface design, an increment of 5.8% oil recovery and 4% net CO2 storage was achieved from 25 cycles to 35 cycles, suggesting ending the injection at 25 cycles. Using the models, distinct optimizations were also computed for oil recovery and net CO2 sequestration in various reservoir conditions. The results expressed a maximum oil recovery from 22% to 30% oil in place (OIP) and around 21,000–29,000 tons of CO2 trapped underground after 35 cycles if the injection began at 60% water saturation. The new approach presented in this study of applying an ANN is obviously effective in forecasting and managing the entire CO2 injection process instead of a single output as presented in previous studies.

Long-term Strategy Optimization of Scale Squeeze Treatment in a Carbonate Reservoir Under CO2-WAG Water-Alternating-Gas Injection

2021 ◽  
Author(s):  
Vahid Azari ◽  
Hydra Rodrigues ◽  
Alina Suieshova ◽  
Oscar Vazquez ◽  
Eric Mackay
Keyword(s):  
Net Present Value ◽  
Co2 Storage ◽  
Gas Injection ◽  
Carbonate Reservoir ◽  
Co2 Injection ◽  
Base Case ◽  
Production Well ◽  
Water Alternating Gas ◽  
Gradient Descent Algorithm

Abstract The objective of this study is to design a series of squeeze treatments for 20 years of production of a Brazilian pre-salt carbonate reservoir analogue, minimizing the cost of scale inhibition strategy. CO2-WAG (Water-Alternating-Gas) injection is implemented in the reservoir to increase oil recovery, but it may also increase the risk of scale deposition. Dissolution of CaCO3 as a consequence of pH decrease during the CO2 injection may result in a higher risk of calcium carbonate precipitation in the production system. The deposits may occur at any location from production bottom-hole to surface facilities. Squeeze treatment is thought to be the most efficient technique to prevent CaCO3 deposition in this reservoir. Therefore, the optimum WAG design for a quarter 5-spot model, with the maximum Net Present Value (NPV) and CO2 storage volume identified from a reservoir optimization process, was considered as the basis for optimizing the squeeze treatment strategy, and the results were compared with those for a base-case waterflooding scenario. Gradient Descent algorithm was used to identify the optimum squeeze lifetime duration for the total lifecycle. The main objective of squeeze strategy optimization is to identify the frequency and lifetime of treatments, resulting in the lowest possible expenditure to achieve water protection over the well's lifecycle. The simulation results for the WAG case showed that the scale window elongates over the last 10 years of production after water breakthrough in the production well. Different squeeze target lifetimes, ranging from 0.5 to 6 million bbl of produced water were considered to optimize the lifetime duration. The optimum squeeze lifetime was identified as being 2 million bbl of protected water, which was implemented for the subsequent squeeze treatments. Based on the water production rate and saturation ratio over time, the optimum chemical deployment plan was calculated. The optimization results showed that seven squeeze treatments were needed to protect the production well in the WAG scenario, while ten treatments were necessary in the waterflooding case, due to the higher water rate in the production window. The novelty of this approach is the ability to optimize a series of squeeze treatment designs for a long-term production period. It adds valuable information at the Front-End Engineering and Design (FEED) stage in a field, where scale control may have a significant impact on the field's economic viability.

Will Carbon Dioxide Injection in Shale Reservoirs Produce from the Shale Matrix, Natural Fractures, or Hydraulic Fractures?

2021 ◽  
Author(s):  
Sherif Fakher ◽  
Youssef Elgahawy ◽  
Hesham Abdelaal ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Fractured Reservoirs ◽  
Co2 Injection ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Recovery Potential ◽  
Shale Reservoirs ◽  
The Impact

Abstract Enhanced oil recovery (EOR) in shale reservoirs has been recently shown to increase oil recovery significantly from this unconventional oil and gas source. One of the most studied EOR methods in shale reservoirs is gas injection, with a focus on carbon Dioxide (CO2) mainly due to the ability to both enhance oil recovery and store the CO2 in the formation. Even though several shale plays have reported an increase in oil recovery using CO2 injection, in some cases this method failed severely. This research attempts to investigate the ability of the CO2 to mobilize crude oil from the three most prominent features in the shale reservoirs, including shale matrix, natural fractures, and hydraulically induced fracture. Shale cores with dimensions of 1 inch in diameter and approximately 1.5 inch in length were used in all experiments. The impact of CO2 soaking time and soaking pressure on the oil recovery were studied. The cores were analyzed to understand how and where the CO2 flowed inside the cores and which prominent feature resulted in the increase in oil recovery. Also, a pre-fractured core was used to run an experiment in order to understand the oil recovery potential from fractured reservoirs. Results showed that oil recovery occurred from the shale matrix, stimulation of natural fractures by the CO2, and from the hydraulic fractures with a large volume coming from the stimulated natural fractures. By understanding where the CO2 will most likely be most productive, proper design of the CO2 EOR in shale can be done in order to maximize recovery and avoid complications during injection and production which may lead to severe operational problems.

Numerical Simulations of Surfactant Flooding in Carbonate Reservoirs: The Impact of Geological Heterogeneities Across Scales

2021 ◽  
Author(s):  
Jackson Pola ◽  
Sebastian Geiger ◽  
Eric Mackay ◽  
Christine Maier ◽  
Ali Al-Rudaini
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Spontaneous Imbibition ◽  
Numerical Dispersion ◽  
Surfactant Flooding ◽  
Production Forecast ◽  
Geological Heterogeneity ◽  
Grid Coarsening ◽  
The Impact ◽  
The Way

Abstract We demonstrate how geological heterogeneity impacts the effectiveness of surfactant-based enhanced oil recovery (EOR) at larger (inter-well and sector) scales when upscaling small (core) scale heterogeneity and physicochemical processes. We used two experimental datasets of surfactant-based EOR where spontaneous imbibition and viscous displacement, respectively dominate recovery. We built 3D core-scale simulation models to match the data and parameterize surfactant models. The results were deployed in high-resolution models that preserve the complexity and heterogeneity of carbonate formations in the inter-well and sector scale. These larger-scale models were based on two outcrop analogues from France and Morroco, respectively, which capture the reservoir architectures inherent to the productive carbonate reservoir systems in the Middle East. We then assessed and quantified the error in production forecast that arises due to upscaling, upgridding, and simplification of geological heterogeneity. Simulation results showed a broad range of recovery predictions. The variability arises from the choice of surfactant model parameterization (i.e., spontaneous imbibition vs viscous displacement) and the way the heterogeneity in the inter-well and sector models was upscaled and simplified. We found that the parameterization of surfactant models has a significant impact on recovery predictions. Oil recovery at the larger scale was observed to be higher when using the parametrization derived from viscous displacement experiments compared to parameterization from spontaneous imbibition experiments. This observation clearly demonstrated how core-scale processes impact recovery predictions at the larger scales. Also, the variability in recovery prediction due to the choice of surfactant model was as large as the variability arising from upscaling and upgridding. Upscaled and upgridded models overestimated recovery because of the simplified geology. Grid coarsening exacerbated this effect because of the increased numerical dispersion. These results emphasize the need to use correctly configured surfactant models, appropriate grid resolution that minimizes numerical dispersion, and properly upscaled reservoir models to accurately forecast surfactant floods. Our findings present new insights into how the uncertainty in production forecasts during surfactant flooding depends on the way surfactant models are parameterized, how the reservoir geology is upscaled, and how numerical dispersion is impacted by grid coarsening.

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