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

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.

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.

Design of in-Depth Conformance Gel Treatment to De-Risk ASP Flooding in a Major Carbonate Reservoir

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Abrahim A. Hassan ◽  
Deema Alrukaibi ◽  
Amna Al-Qenae ◽  
Jimmy Nesbit ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
Significant Risk ◽  
High Viscosity ◽  
Carbonate Reservoir ◽  
High Permeability ◽  
Laboratory Design ◽  
Gel Treatment ◽  
Viscosity Polymer ◽  
Chromium Acetate

Abstract Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor sweep efficiency, both areal and microscopic. An Alkaline-Surfactant-Polymer (ASP) pilot is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Design of the gel conformance treatment was multi-faceted. Rapid breakthrough of tracers at the pilot producer from each of the individual injectors, less than 3 days, implied a direct connection from the injectors to the producer and poses significant risk to the success of the pilot. A dynamic model of the SAMA pilot was used to estimate in the potential injection of either a high viscous polymer solution (~200 cp) or a gel conformance treatment to improve contact efficiency, diverting injected fluid into oil saturated reservoir matrix. High viscosity polymer injection scenarios were simulated in the extracted subsector model and showed little to no effect on diverting fluids from the high permeability streak into the matrix. Gel conformance treatment, however, provides benefit to the SAMA pilot with important limitations. Gel treatment diverts injected fluid from the high permeability zone into lower permeability, higher oil saturated reservoir. After a gel treatment, the ASP increases the oil cut from 3% to 75% while increasing the cumulative oil recovery by more than 50 MSTB oil over ASP following a high viscosity polymer slug alone. Laboratory design of the gel conformance system for the SAMA ASP pilot involved blending of two polymer types (AN 125SH, an ATBS type polymer, and P320 VLM and P330, synthetic copolymers) and two crosslinkers (chromium acetate and X1050, an organic crosslinker). Bulk testing with the polymer-crosslinker combinations indicated that SAMA reservoir brine resulted in not gel system that would work in the SAMA reservoir, resulting in the recommendation of using 2% KCl in treated water for gel formulation. AN 125 SH with S1050 produce good gels but with short gelation times and AS 125 SH with chromium acetate developed low gels consistency in both waters. P330 and P320 VLM gave good gels with slow gelation times with X1050 crosslinker in 2% KCl. Corefloods with the P330-X 1050 showed good injectivity and ultimately a reduction of permeability of about 200-fold. A P330-X 1050 was recommended for numerical simulation studies. Numerical simulator was calibrated by matching bulk gel viscosity increases and coreflood permeability changes. Numerical simulation indicated two of the four injection wells (SA-0557 and SA-0559) injection profile will change compared to water. Overall injection rate was reduced by the conformance treatment and was the corresponding oil rate. Total oil production from the center pilot production well (SA-0560) decreased with gel treatment but ultimately increased to greater rates

scholarly journals Study on the Interaction between Low-Viscosity High-Permeability Pregrouting Sealing Material and Coal and Its Application

2020 ◽  
Vol 2020 ◽  
pp. 1-11
Author(s):  
Yujia Chen ◽  
Ao Li ◽  
Dingding Yang ◽  
Tianyu Liu ◽  
Xiaowei Li ◽  
...  
Keyword(s):  
Coal Seam ◽  
Bending Strength ◽  
Formation Rate ◽  
Field Application ◽  
Gas Pressure ◽  
Polymer Materials ◽  
Target System ◽  
High Permeability ◽  
Low Viscosity ◽  
New Material

In order to ensure the intactness of pressure-measuring boreholes and the accuracy of gas pressure determination, pregrouting treatment with polymer materials is frequently applied to bedding drilling in coal mines. However, the existing polyurethane materials are of high viscosity, low permeability, and poor safety, bringing great difficulties to their field promotion and application. In view of this problem, after optimization and experiments, polylactide polyol/polyether polyol 4110/isocyanate was determined as the target system. Bio-based benzoxazine (Boz-F), red phosphorus, and melamine with a mass ratio of 2 : 1 : 2 were used as the flame retardant, which then underwent mechanical modification by hollow glass bubbles. Finally, the pregrouting material with low viscosity and high permeability was compounded, and its interaction with coal was experimentally studied. The results show that compared with traditional polyurethane, the new material increases the effective consolidation distance in the coal seam by 40% on average. Its permeation radius is also larger than the calculated radius of the plastic softening zone of a borehole. In addition, the strengths of coal-new material consolidated products with different ratios fully surpass those of coal-polyurethane material consolidated products. The enhancement of compressive strength and bending strength is up to 153% and 161%, respectively. The field application indicates that after pregrouting treatment of boreholes in the coal seam with the new material, the borehole formation rate reaches 100%. Therefore, the new material is safe and practical for gas pressure measurement through bedding drilling on site.

scholarly journals Impact of Brine Composition and Concentration on Capillary Pressure and Residual Oil Saturation in Limestone Core Samples

2019 ◽  
Vol 89 ◽  
pp. 02006
Author(s):  
F. Feldmann ◽  
A. M. AlSumaiti ◽  
S. K. Masalmeh ◽  
W. S. AlAmeri ◽  
S. Oedai
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Spontaneous Imbibition ◽  
Oil Saturation ◽  
Salinity Effect ◽  
Connate Water ◽  
Low Salinity ◽  
Remaining Oil ◽  
The Impact ◽  
Secondary Mode

Low salinity water flooding (LSF) is a relatively simple and cheap EOR technique in which the salinit y of the injected water is optimized (by desalination and/or modification) to improve oil recovery over conventional waterflooding. Extensive laboratory experiments investigating the effect of LSF are available in the literature. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. For the first time in literature, this paper presents a comprehensive study of the centrifuge technique to investigate low salinity effect in carbonate samples. The study is divided into three parts. At first, a comprehensive screening was performed on the impact of different connate water and imbibition brine compositions/combinations on the spontaneous imbibition behavior. Second, the subsequent forced imbibition of the samples using the centrifuge method to investigate the impact of brine compositions on residual saturations and capillary pressure. Finally, three unsteady-state (USS) core floodings were conducted in order to examine the potential of the different brines to increase oil recovery in secondary mode (brine injection at connate water saturation) and tertiary mode (exchange of injection brine at mature recovery stage). The experiments were performed using Indiana limestone outcrops. The main conclusions of the study are spontaneous imbibition experiments only showed oil recovery in case the salinity of the imbibing water (IW) is lower than the salinity of the connate water (CW). No oil production was observed when the imbibing water had a higher salinity than the connate water or the salinity of the connate water and imbibing brine were identical. Moreover, the spontaneous imbibition experiments indicated that diluting the salinity of the imbibing water has a larger potential to spontaneously recover oil than the introduction of sulfate-rich sea water. The centrifuge experiments confirmed a connection between the overall salinity and oil recovery. As the salinity of the imbibing brines decreases, the capillary imbibition pressure curves showed an increasing water-wetting tendency and simultaneous reduction of the remaining oil saturation. The lowest remaining oil saturation was obtained for diluted sea water as CW and IW. The core flooding experiments reflected the results of the spontaneous imbibition and centrifuge experiments. Injecting brine at a rate of 0.05 cc/min, sea water and especially diluted sea water resulted in a significant higher oil recovery compared to formation brine. Moreover, when comparing secondary mode experiments, the remaining oil saturation after flooding by diluted sea water, sea water and formation water was 30.6 %, 35.5 % and 37.4 %, respectively. In tertiary injection mode, sea water did not lead to extra oil recovery while diluted sea water led to an additional oil recovery of 5.6 % in one out of two tertiary injection applications.

Foam Diversion in Heterogeneous Reservoirs: Effect of Permeability and Injection Method

SPE Journal ◽  
2017 ◽  
Vol 22 (05) ◽  
pp. 1402-1415 ◽  
Author(s):  
A. H. Al Ayesh ◽  
R.. Salazar ◽  
R.. Farajzadeh ◽  
S.. Vincent-Bonnieu ◽  
W. R. Rossen
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Gas Injection ◽  
Surfactant Solution ◽  
Model Parameters ◽  
High Permeability ◽  
Fractional Flow ◽  
Injection Method ◽  
Heterogeneous Reservoirs ◽  
Irreducible Water Saturation

Summary Foam can divert flow from higher- to lower-permeability layers and thereby improve the injection profile in gas-injection enhanced oil recovery (EOR). This paper compares two methods of foam injection, surfactant-alternating-gas (SAG) and coinjection of gas and surfactant solution, in their abilities to improve injection profiles in heterogeneous reservoirs. We examine the effects of these two injection methods on diversion by use of fractional-flow modeling. The foam-model parameters for four sandstone formations ranging in permeability from 6 to 1,900 md presented by Kapetas et al. (2015) are used to represent a hypothetical reservoir containing four noncommunicating layers. Permeability affects both the mobility reduction of wet foam in the low-quality-foam regime and the limiting capillary pressure at which foam collapses. The effectiveness of diversion varies greatly with the injection method. In a SAG process, diversion of the first slug of gas depends on foam behavior at very-high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. (2015). Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This favors diversion away from high-permeability layers that receive a large surfactant slug. However, there is an optimum surfactant-slug size: Too little surfactant and diversion from high-permeability layers is not effective, whereas with too much, mobility is reduced in low-permeability layers. For a SAG process, injectivity and diversion depend critically on whether foam collapses completely at irreducible water saturation. In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with injection time. Injectivity is extremely poor with foam injection for these extremely strong foams, but for some SAG foam processes with effective diversion it is better than injectivity in a waterflood.

Pressure Maintenance and Improving Oil Recovery by Means of Immiscible Water-Alternating-CO2 Processes in Thin Heavy-Oil Reservoirs

2013 ◽  
Vol 16 (01) ◽  
pp. 60-71 ◽  
Author(s):  
Sixu Zheng ◽  
Daoyong Yang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Horizontal Wells ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Oil Saturation ◽  
Water Alternating Gas ◽  
Heavy Oil Reservoirs ◽  
Water Cut

Summary Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy-oil reservoirs for pressure maintenance and improving oil recovery. Experimentally, a 3D physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy-oil recovery. The corresponding initial oil saturation, oil-production rate, water cut, oil recovery, and residual-oil-saturation (ROS) distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water/CO2 ratio). The incremental oil recoveries of 12.4 and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governing water-alternating-CO2 processes have been numerically simulated and matched. It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and oil recovery in thin heavy-oil reservoirs. Although well configuration imposes a dominant impact on oil recovery, the water-alternating-gas (WAG) ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios 1 and 2, respectively.

Study of Enhanced-Oil-Recovery Mechanism of Alkali/Surfactant/Polymer Flooding in Porous Media From Experiments

SPE Journal ◽  
2009 ◽  
Vol 14 (02) ◽  
pp. 237-244 ◽  
Author(s):  
Pingping Shen ◽  
Jialu Wang ◽  
Shiyi Yuan ◽  
Taixian Zhong ◽  
Xu Jia
Keyword(s):  
Porous Media ◽  
Fluid Flow ◽  
Oil Recovery ◽  
Production Performance ◽  
Residual Oil ◽  
Flow Mechanism ◽  
Displacement Efficiency ◽  
High Permeability ◽  
Heterogeneous Reservoir ◽  
Asp Flooding

Summary The fluid-flow mechanism of enhanced oil recovery (EOR) in porous media by alkali/surfactant/polymer (ASP) flooding is investigated by measuring the production performance, pressure, and saturation distributions through the installed differential-pressure transducers and saturation-measurement probes in a physical model of a vertical heterogeneous reservoir. The fluid-flow variation in the reservoir is one of the main mechanisms of EOR of ASP flooding, and the nonlinear coupling and interaction between pressure and saturation fields results in the fluid-flow variation in the reservoir. In the vertical heterogeneous reservoir, the ASP agents flow initially in the high-permeability layer. Later, the flow direction changes toward the low- and middle-permeability layers because the resistance in the high-permeability layer increases on physical and chemical reactions such as adsorption, retention, and emulsion. ASP flooding displaces not only the residual oil in the high-permeability layer but also the remaining oil in the low- and middle-permeability layers by increasing both swept volume and displacement efficiency. Introduction Currently, most oil fields in China are in the later production period and the water cut increases rapidly, even to more than 80%. Waterflooding no longer meets the demands of oilfield production. Thus, it is inevitable that a new technology will replace waterflooding. The new technique of ASP flooding has been developed on the basis of alkali-, surfactant-, and polymer-flooding research in the late 1980s. ASP flooding uses the benefits of the three flooding methods simultaneously, and oil recovery is greatly enhanced by decreasing interfacial tension (IFT), increasing the capillary number, enhancing microscopic displacing efficiency, improving the mobility ratio, and increasing macroscopic sweeping efficiency (Shen and Yu 2002; Wang et al. 2000; Wang et al. 2002; Sui et al. 2000). Recently, much intensive research has been done on ASP flooding both in China and worldwide, achieving some important accomplishments that lay a solid foundation for the extension of this technique to practical application in oil fields (Baviere et al. 1995; Thomas 2005; Yang et al. 2003; Li et al. 2003). In previous work, the ASP-flooding mechanism was studied visually by using a microscopic-scale model and double-pane glass models with sand (Liu et al. 2003; Zhang 1991). In these experiments, the water-viscosity finger, the residual-oil distribution after waterflooding, and the oil bank formed by microscopic emulsion flooding were observed. In Tong et al. (1998) and Guo (1990), deformation, threading, emulsion (oil/water), and strapping were observed as the main mechanisms of ASP flooding in a water-wetting reservoir, while the interface-producing emulsion (oil/water), bridging between inner pore and outer pore, is the main mechanism of ASP flooding in an oil-wetting reservoir. For a vertical heterogeneous reservoir, ASP flooding increases displacement efficiency by displacing residual oil through decreased IFT, simultaneously improving sweep efficiency by extending the swept area in both vertical and horizontal directions. Some physical and chemical phenomena, such as emulsion, scale deposition, and chromatographic separation, occur during ASP flooding (Arihara et al. 1999; Guo 1999). Because ASP flooding in porous media involves many complicated physicochemical properties, many oil-recovery mechanisms still need to be investigated. Most research has been performed on the microscopic displacement mechanism of ASP flooding, while the fluid-flow mechanism in porous media at the macroscopic scale lacks sufficient study. In this paper, a vertical-heterogeneous-reservoir model is established, and differential-pressure transducers and saturation-measuring probes are installed. The fluid-flow mechanism of increasing both macroscopic sweep efficiency and microscopic displacement efficiency is studied by measuring the production performance and the variation of pressure and saturation distributions in the ASP-flooding experiment. An experimental database of ASP flooding also is set up and provides an experimental base for numerical simulation.

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.

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