scholarly journals Improved Water Injection Index Curve on Estimation of Oil in Place for Fractured Vuggy Carbonate Reservoirs

2020 ◽  
Vol 8 (6) ◽  
pp. 124
Author(s):  
Fan Haijun ◽  
Kang Zhijiang ◽  
Zheng Songqing ◽  
Zhu Guiliang
Keyword(s):  
Water Injection ◽  
Carbonate Reservoirs ◽  
Index Curve

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.

Polymer Injection to Unlock Bypassed Oil in a Giant Carbonate Reservoir: Bridging the Gap Between Laboratory and Large Scale Polymer Project

2021 ◽  
Author(s):  
Clement Fabbri ◽  
Haitham Ali Al Saadi ◽  
Ke Wang ◽  
Flavien Maire ◽  
Carolina Romero ◽  
...  
Keyword(s):  
High Salinity ◽  
Water Injection ◽  
Cross Flow ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Laboratory Work ◽  
High Permeability ◽  
Polymer Injection ◽  
Single Well ◽  
Pilot Design

Abstract Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs where polymer enhances cross flow between layers and forces water into the low permeability layers, leading to more homogeneous saturation profile. Although this approach could unlock large volumes of by-passed oil in layered carbonate reservoirs, compatibility of polymer solutions with high salinity - high temperature carbonate reservoirs has been hindering polymer injection projects in such harsh conditions. The aim of this paper is to present the laboratory work, polymer injection field test results and pilot design aimed to unlock target tertiary oil recovery in a highly heterogeneous mixed to oil-wet giant carbonate reservoir. This paper focuses on a highly layered limestone reservoir with various levels of cyclicity in properties. This reservoir may be divided in 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 peripheral and mid-flank water injection. 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 setting, adequate polymer injection strategy to enhance cross-flow between these zones is investigated, building on laboratory and polymer injection test field results. A key prerequisite for defining such EOR development scenario is to have representative static and dynamic models that captures the geological heterogeneity of this kind of reservoirs. This is achieved by an improved and integrated reservoir characterization, modelling and water injection history matching procedure. The history matched model was used to investigate different polymer injection schemes and resulted in an optimum pilot design. The injection scheme is defined based on dynamic simulations to maximize value, building on results from single-well polymer injection test, laboratory work and on previous published work, which have demonstrated the potential of polymer flooding for this reservoir. Our study evidences the positive impact of polymer propagation at field scale, improving the water-front stability, which is a function of pressure gradient near producer wells. Sensitivities to the position and number of polymer injectors have been performed to identify the best injection configuration, depending on the existing water injection scheme and the operating constraints. The pilot design proposed builds on laboratory work and field monitoring data gathered during single-well polymer injection field test. Together, these elements represent building blocks to enable tertiary polymer recovery in giant heterogeneous carbonate reservoirs with high temperature - high salinity conditions.

scholarly journals Improved CRM Model for Inter-Well Connectivity Estimation and Production Optimization: Case Study for Karst Reservoirs

Energies ◽  
2019 ◽  
Vol 12 (5) ◽  
pp. 816 ◽  
Author(s):  
Daigang Wang ◽  
Yong Li ◽  
Jing Zhang ◽  
Chenji Wei ◽  
Yuwei Jiao ◽  
...  
Keyword(s):  
Time Delay ◽  
Net Present Value ◽  
Water Injection ◽  
Injection Rate ◽  
Production Optimization ◽  
Carbonate Reservoirs ◽  
Karst Reservoir ◽  
Control Step ◽  
Multi Phase Flow

Due to the coexistence of multiple types of reservoir bodies and widely distributed aquifer support in karst carbonate reservoirs, it remains a great challenge to understand the reservoir flow dynamics based on traditional capacitance–resistance (CRM) models and Darcy’s percolation theory. To solve this issue, an improved injector–producer-pair-based CRM model coupling the effect of active aquifer support was first developed and combined with the newly-developed Stochastic Simplex Approximate Gradient (StoSAG) optimization algorithm for accurate inter-well connectivity estimation in a waterflood operation. The improved CRM–StoSAG workflow was further applied for real-time production optimization to find the optimal water injection rate at each control step by maximizing the net present value of production. The case study conducted for a typical karst reservoir indicated that the proposed workflow can provide good insight into complex multi-phase flow behaviors in karst carbonate reservoirs. Low connectivity coefficient and time delay constant most likely refer to active aquifer support through a high-permeable flow channel. Moreover, the injector–producer pair may be interconnected by complex fissure zones when both the connectivity coefficient and time delay constant are relatively large.

scholarly journals Enhanced Wettability Modification and CO2 Solubility Effect by Carbonated Low Salinity Water Injection in Carbonate Reservoirs

2017 ◽  
Vol 2017 ◽  
pp. 1-10 ◽  
Author(s):  
Ji Ho Lee ◽  
Kun Sang Lee
Keyword(s):  
Oil Recovery ◽  
Saline Water ◽  
Water Injection ◽  
Carbonate Reservoirs ◽  
Viscosity Reduction ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Geochemical Reactions ◽  
Salinity Water ◽  
Low Salinity Water Injection

Carbonated water injection (CWI) induces oil swelling and viscosity reduction. Another advantage of this technique is that CO2 can be stored via solubility trapping. The CO2 solubility of brine is a key factor that determines the extent of these effects. The solubility is sensitive to pressure, temperature, and salinity. The salting-out phenomenon makes low saline brine a favorable condition for solubilizing CO2 into brine, thus enabling the brine to deliver more CO2 into reservoirs. In addition, low saline water injection (LSWI) can modify wettability and enhance oil recovery in carbonate reservoirs. The high CO2 solubility potential and wettability modification effect motivate the deployment of hybrid carbonated low salinity water injection (CLSWI). Reliable evaluation should consider geochemical reactions, which determine CO2 solubility and wettability modification, in brine/oil/rock systems. In this study, CLSWI was modeled with geochemical reactions, and oil production and CO2 storage were evaluated. In core and pilot systems, CLSWI increased oil recovery by up to 9% and 15%, respectively, and CO2 storage until oil recovery by up to 24% and 45%, respectively, compared to CWI. The CLSWI also improved injectivity by up to 31% in a pilot system. This study demonstrates that CLSWI is a promising water-based hybrid EOR (enhanced oil recovery).

Chelating-Agent Enhanced Oil Recovery for Sandstone and Carbonate Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 483-495 ◽  
Author(s):  
M. A. Mahmoud ◽  
K. Z. Abdelgawad
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Chelating Agents ◽  
Water Injection ◽  
Chelating Agent ◽  
Carbonate Reservoirs ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Core Permeability

Summary Recently low-salinity waterflooding was introduced as an effective enhanced-oil-recovery (EOR) method in sandstone and carbonate reservoirs. The recovery mechanisms that use low-salinity-water injection are still debatable. The suggested possible mechanisms are: wettability alteration, interfacial-tension (IFT) reduction, multi-ion exchange, and rock dissolution. In this paper, we introduce a new chemical EOR method for sandstone and carbonate reservoirs that will give better recovery than the low-salinity-water injection without treating or diluting seawater. In this study, we introduce a new chemical EOR method that uses chelating agents such as ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediaminetriacetic acid (HEDTA), and diethylenetriaminepentaacetic acid (DTPA) at high pH values. This is the first time for use of chelating agents as standalone EOR fluids. Coreflood experiments, interfacial and surface tensions, and zeta-potential measurements are performed with DTPA, EDTA, and HEDTA chelating agents. The chelating-agent concentrations used in the study were prepared by diluting the initial concentration of 40 wt% with seawater and injecting it into Berea-sandstone and Indiana-limestone cores of a 6-in. length and a 1.5-in. diameter saturated with crude oil. The coreflooding experiments were performed at 100°C and a 1,000-psi backpressure. Low-salinity-water and seawater injections caused damage to the reservoir because of the calcium sulfate scale deposition during the flooding process. The newly introduced EOR method did not cause calcium sulfate precipitation, and the core permeability was not affected. The core permeability was measured after the flooding process, and the final permeability was higher than the initial permeability in the case of chelating-agent injection. The coreflooding effluent was analyzed for cations with the inductively coupled plasma (ICP) spectroscopy to explain the dissolution-recovery mechanism. The effect of iron minerals on the rock-surface charge was investigated through the measurements of zeta potential for different rocks containing different iron minerals. HEDTA and EDTA chelating agents at 5 wt% concentration prepared in seawater were able to recover more than 20% oil from the initial oil in place from sandstone and carbonate cores. ICP measurements supported the rock-dissolution mechanism because the calcium, magnesium, and iron concentrations in the effluent samples were more than those in the injected fluids. The IFT-reduction mechanism was confirmed by the low IFT values obtained in the case of chelating agents. The type and concentration of chelating agents affected the IFT value. Higher concentrations yielded lower IFT values because of the increase in carboxylic-group concentration. We found that the high-pH chelating agents increased the negative value of zeta potential, which will change the rock toward more water-wet.

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