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 Injection-production optimization of carbonate reservoir based on an inter-well connectivity model

2021 ◽  
pp. 014459872199465
Author(s):  
Yuhui Zhou ◽  
Sheng Lei ◽  
Xuebiao Du ◽  
Shichang Ju ◽  
Wei Li
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Field Application ◽  
Carbonate Reservoir ◽  
Production Optimization ◽  
Oil Field ◽  
Carbonate Reservoirs ◽  
Utilization Rate ◽  
Production Volume ◽  
Connectivity Model

Carbonate reservoirs are highly heterogeneous. During waterflooding stage, the channeling phenomenon of displacing fluid in high-permeability layers easily leads to early water breakthrough and high water-cut with low recovery rate. To quantitatively characterize the inter-well connectivity parameters (including conductivity and connected volume), we developed an inter-well connectivity model based on the principle of inter-well connectivity and the geological data and development performance of carbonate reservoirs. Thus, the planar water injection allocation factors and water injection utilization rate of different layers can be obtained. In addition, when the proposed model is integrated with automatic history matching method and production optimization algorithm, the real-time oil and water production can be optimized and predicted. Field application demonstrates that adjusting injection parameters based on the model outputs results in a 1.5% increase in annual oil production, which offers significant guidance for the efficient development of similar oil reservoirs. In this study, the connectivity method was applied to multi-layer real reservoirs for the first time, and the injection and production volume of injection-production wells were repeatedly updated based on multiple iterations of water injection efficiency. The correctness of the method was verified by conceptual calculations and then applied to real reservoirs. So that the oil field can increase production in a short time, and has good application value.

Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?

2014 ◽  
Vol 17 (03) ◽  
pp. 304-313 ◽  
Author(s):  
A.M.. M. Shehata ◽  
M.B.. B. Alotaibi ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Oil Recovery ◽  
Sudden Change ◽  
Oil Production ◽  
Deionized Water ◽  
Production Performance ◽  
Shallow Aquifer ◽  
Secondary Recovery ◽  
Tertiary Recovery ◽  
The Impact ◽  
Indiana Limestone

Summary Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO42−) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO42− ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

Saturated carbon dioxide nanofluids enhanced oil recovery in carbonate reservoir cores using nuclear magnetic resonance

2021 ◽  
Author(s):  
Yongsheng Tan ◽  
Qi Li ◽  
Liang Xu ◽  
Xiaoyan Zhang ◽  
Tao Yu
Keyword(s):  
Carbon Dioxide ◽  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Residual Oil ◽  
Core Flooding ◽  
Nuclear Magnetic

<p>The wettability, fingering effect and strong heterogeneity of carbonate reservoirs lead to low oil recovery. However, carbon dioxide (CO<sub>2</sub>) displacement is an effective method to improve oil recovery for carbonate reservoirs. Saturated CO<sub>2</sub> nanofluids combines the advantages of CO<sub>2</sub> and nanofluids, which can change the reservoir wettability and improve the sweep area to achieve the purpose of enhanced oil recovery (EOR), so it is a promising technique in petroleum industry. In this study, comparative experiments of CO<sub>2</sub> flooding and saturated CO<sub>2</sub> nanofluids flooding were carried out in carbonate reservoir cores. The nuclear magnetic resonance (NMR) instrument was used to clarify oil distribution during core flooding processes. For the CO<sub>2</sub> displacement experiment, the results show that viscous fingering and channeling are obvious during CO<sub>2</sub> flooding, the oil is mainly produced from the big pores, and the residual oil is trapped in the small pores. For the saturated CO<sub>2</sub> nanofluids displacement experiment, the results show that saturated CO<sub>2</sub> nanofluids inhibit CO<sub>2</sub> channeling and fingering, the oil is produced from the big pores and small pores, the residual oil is still trapped in the small pores, but the NMR signal intensity of the residual oil is significantly reduced. The final oil recovery of saturated CO<sub>2</sub> nanofluids displacement is higher than that of CO<sub>2</sub> displacement. This study provides a significant reference for EOR in carbonate reservoirs. Meanwhile, it promotes the application of nanofluids in energy exploitation and CO<sub>2</sub> utilization.</p>

The New Flow Control Devices Autonomously Controlling the Performance of Matrix Acid Stimulation Operations in Carbonate Reservoirs

2021 ◽  
Author(s):  
Mojtaba Moradi ◽  
Michael R Konopczynski
Keyword(s):  
Flow Control ◽  
Dynamic Change ◽  
Injection Rate ◽  
Control Flow ◽  
Carbonate Reservoir ◽  
Operating Conditions ◽  
Carbonate Reservoirs ◽  
High Permeability ◽  
The Impact ◽  
Stimulation Of

Abstract Matrix acidizing is a common but complex stimulation treatment that could significantly improve production/injection rate, particularly in carbonate reservoirs. However, the desired improvement in all zones of the well by such operation may not be achieved due to existing and/or developing reservoir heterogeneity. This paper describes how a new flow control device (FCD) previously used to control water injection in long horizontal wells can also be used to improve the conformance of acid stimulation in carbonate reservoirs. Acid stimulation of a carbonate reservoir is a positive feedback process. Acid preferentially takes the least resistant path, an area with higher permeability or low skin. Once acid reacts with the formation, the injectivity in that zone increases, resulting in further preferential injection in the stimulated zone. Over-treating a high permeability zone results in poor distribution of acid to low permeability zones. Mechanical, chemical or foam diversions have been used to improve stimulation conformance along the wellbore, however, they may fail in carbonate reservoirs with natural fractures where fracture injectivity dominates the stimulation process. A new FCD has been developed to autonomously control flow and provide mechanical diversion during matrix stimulation. Once a predefined upper limit flowrate is reached at a zone, the valve autonomously closes. This eliminates the impact of thief zone on acid injection conformance and maintains a prescribed acid distribution. Like other FCDs, this device is installed in several compartments in the wells. The device has two operating conditions, one, as a passive outflow control valve, and two, as a barrier when the flow rate through the valve exceeds a designed limit, analogous to an electrical circuit breaker. Once a zone has been sufficiently stimulated by the acid and the injection rate in that zone exceeds the device trip point, the device in that zone closes and restricts further stimulation. Acid can then flow to and stimulate other zones This process can be repeated later in well life to re-stimulate zones. This performance enables the operators to minimise the impacts of high permeability zones on the acid conformance and to autonomously react to a dynamic change in reservoirs properties, specifically the growth of wormholes. The device can be installed as part of lower completions in both injection and production wells. It can be retrofitted in existing completions or be used in a retrievable completion. This technology allows repeat stimulation of carbonate reservoirs, providing mechanical diversion without the need for coiled tubing or other complex intervention. This paper will briefly present an overview of the device performance, flow loop testing and some results from numerical modelling. The paper also discusses the completion design workflow in carbonates reservoirs.

scholarly journals Breccia interlayer effects on steam-assisted gravity drainage performance: experimental and numerical study

2021 ◽  
Author(s):  
Qichen Zhang ◽  
Xiaodong Kang ◽  
Huiqing Liu ◽  
Xiaohu Dong ◽  
Jian Wang
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
Oil Sands ◽  
Numerical Study ◽  
Middle Part ◽  
Experimental Results ◽  
Production Performance ◽  
Peak Oil ◽  
Steam Chamber ◽  
The Impact

AbstractCurrently, the reservoir heterogeneity is a serious challenge for developing oil sands with SAGD method. Nexen’s Long Lake SAGD project reported that breccia interlayer was widely distributed in lower and middle part of reservoir, impeding the steam chamber expansion and heated oil drainage. In this paper, two physical experiments were conducted to study the impact of breccia interlayer on development of steam chamber and production performance. Then, a laboratory scale numerical simulation model was established and a history match was conducted based on the 3D experimental results. Finally, the sensitivity analysis of thickness and permeability of breccia layer was performed. The influence mechanism of breccia layer on SAGD performance was analyzed by comparing the temperature profile of steam chamber and production dynamics. The experimental results indicate that the existence of breccia interlayer causes a thinner steam chamber profile and longer time to reach the peak oil rate. And, the ultimate oil recovery reduced 15.8% due to much oil stuck in breccia interlayer areas. The numerical simulation results show that a lower permeability in breccia layer area has a serious adverse impact on oil recovery if the thickness of breccia layer is larger, whereas the effect of permeability on SAGD performance is limited when the breccia layer is thinner. Besides, a thicker breccia layer can increase the time required to reach the peak oil rate, but has a little impact on the ultimate oil recovery.

An experimental study for carbonate reservoirs on the impact of CO2-EOR on petrophysics and oil recovery

Fuel ◽  
2019 ◽  
Vol 235 ◽  
pp. 1019-1038 ◽  
Author(s):  
Mohamed Khather ◽  
Ali Saeedi ◽  
Matthew B. Myers ◽  
Michael Verrall
Keyword(s):  
Experimental Study ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Co2 Eor ◽  
The Impact

scholarly journals Compatibility evaluation of modified seawater for EOR in carbonate reservoirs through the introduction of polyphosphate compound

2019 ◽  
Vol 17 (2) ◽  
pp. 393-408 ◽  
Author(s):  
Bisweswar Ghosh ◽  
Liying Sun ◽  
Nithin Chacko Thomas
Keyword(s):  
Oil Recovery ◽  
Economic Benefits ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Core Flooding ◽  
Systematic Screening ◽  
Flood Water ◽  
Scaling Potential ◽  
Original Oil In Place ◽  
New Formulation

Abstract Waterflood-assisted oil recovery with sulfate-spiked seawater would cause incompatibility scaling in carbonate reservoirs and reduce economic benefits. This research investigated the benefits of polyphosphate compounds in reducing scaling potential as well as its effect on oil recovery when mixed in high sulfate flood water. Severity of scaling potential of sulfate-spiked water in a carbonate reservoir environment was measured, followed by systematic screening of a polyphosphate compound, which successfully inhibited the sulfate scale precipitation at concentration as low as 100 ppm. The new formulation (seawater with four times sulfate and phosphate, SW4SP) was evaluated and compared with benchmark formulation (modified seawater with four times sulfate, SW4S). Contact angle, ζ-potential and drainage studies show that SW4SP changed the rock wettability from oil wet to water wet to a larger degree compared to SW4S. Improved recovery efficiency of SW4SP was confirmed through a set of core flooding studies in the tertiary and quaternary flood modes. Whereas SW4S recovered 7.7% of original oil in place (OOIP), SW4SP recovered about 8% of OOIP in the tertiary mode under approximately identical flow conditions. Flooding with SW4SP in the quaternary mode following a tertiary flood with SW4S on the same core resulted in 1.7% additional oil recovery, showing improved efficiency of the new flood water formulation.

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.

Comprehensive Well Test Interpretation Method, Process, and Multiple Solutions Analysis for Complicated Carbonate Reservoirs

2019 ◽  
Vol 141 (12) ◽  
Author(s):  
Renfeng Yang ◽  
Ruizhong Jiang ◽  
Shirish Patil ◽  
Shun Liu ◽  
Yihua Gao ◽  
...  
Keyword(s):  
Evaluation Method ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Production Performance ◽  
Physical Parameters ◽  
Test Interpretation ◽  
Well Test ◽  
Pressure Derivative ◽  
Fracture Characteristics ◽  
Parameter Evaluation

Abstract The main characteristic of the complicated carbonate reservoirs is notably strong heterogeneous, leading to a high uncertainty in formation parameter evaluation. The most reliable method for obtaining the dynamic parameters is well test interpretation. However, the well test curve shows similar characteristics for multi-layers reservoirs, dual-medium reservoirs, and carbonate reservoirs with lithology mixed sedimentation lithology. Sometimes the well test fitting result under the mentioned three kinds of models is satisfied, but the interpretation result is quite different. In order to reduce the parameter evaluation multiplicity, the synthetic identification and evaluation method for obtaining the physical parameters of the complicated carbonate reservoir was proposed, based on completion types, core analysis, lithology analysis, and well test results. The evaluation method distinguishes the different carbonate reservoir characteristics from similar well test responses by summarizing and classifying the completion method, reservoir fracture characteristics, and production logging test (PLT) results. The reliability of the proposed method is verified by an application of actual carbonate reservoir parameters evaluation. The proposed method can distinguish among multi-layers reservoirs, dual-medium, and complicated reservoirs with mixed sedimentation lithology whose main characteristic is that concavity existing in the pressure derivative curve. If the well test match results were satisfied enough which lead to the proposed method and process was ignored, the interpretation results and production performance prediction may deviate largely from the actual situation.

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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