scholarly journals Gas-assisted gravity drainage process for improved oil recovery in Bao Den fractured basement reservoir

2016 ◽  
Vol 19 (1) ◽  
pp. 161-168
Author(s):  
Tuan Van Nguyen ◽  
Xuan Van Tran
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
High Water ◽  
Injection Rate ◽  
Oil Field ◽  
Gravity Drainage ◽  
Sweep Efficiency ◽  
Improved Oil Recovery ◽  
North West ◽  
Water Cut

Gas injection has been widely used for Improved Oil Recovery (IOR)/ Enhanced Oil Recovery (EOR) processes in oil reservoirs. Unlike the conventional gas injection (CGI) modes of CGI and Water Alternating Gas (WAG), the Gas-Assisted Gravity Drainage (GAGD) process takes advantage of the natural segregation of reservoir fluids to provide gravity stable oil displacement. It has been proved that GAGD Process results in better sweep efficiency and higher microscopic displacement to recover the bypassed oil from un-swept regions in the reservoir. Therefore, dry gas has been considered for injection in fractured basement reservoir, Bao Den (BD) oil field located in Cuu Long basin through the GAGD process application. This field, with a 5-year production history, has nine production wells and is surrounded by a strong active edge aquifer from the North-West and the South East flanks. The depth of basement granite top is about 2,800 mTVDss with a vertical oil column of 1,500m. The pilot GAGD project has been designed to test an isolated domain in the BD fractured basement reservoir where there is favorable reservoir conditions to implement GAGD. Both reservoir simulation and Lab test have been run and confirmed the feasibility and the benefit of GAGD project in the selected area.The Dry gas will be periodically injected through existing wellwith high water cut production that located in the isolated area. As the injected gas rises to the top to form a gas zone pushing GOC (gas oil contact) downward, and may push WOC (water oil contact) to lower part of this producer (or even away from bottom of the well bore) could lower down water cut when switch this well back to production mode. The matched reservoir model with reservoir and fluid properties have been used to implement sensitivity analysis, the result indicated that there is significantly oil incremental and water cut reduction by GAGDapplication. Many different scenarios have run to find the optimal reservoir performance through GAGD process. Among these runs, the optimal scenario, which has distinct target, requires high levels of gas injection rate to attain the maximum cumulative oil production.

On the Feasibility of Applying Electric Field to Increase Oil Recovery in Old Oil Field

2014 ◽  
Vol 900 ◽  
pp. 677-680
Author(s):  
Chun Hong Nie
Keyword(s):  
Electric Field ◽  
Oil Recovery ◽  
Water Injection ◽  
High Water ◽  
Oil Field ◽  
Thin Layers ◽  
Stable Yield ◽  
High Water Cut Stage ◽  
High Water Cut ◽  
Water Cut

This paper has discussed the characteristics, roles, feasibility and obvious effects of the technology by applying electric field to enhance oil recovery when the oil field is in high water cut stage and super high water cut stage. In view that most oil wells in old oil field have entered into the super high water cut production, the remaining oil in the main reservoir is in fragmented distribution with poor results of water injection and new reserves of oil mostly have a low penetration rate and are thin layers of poor physical properties, the use of the direct current field in period of high water cut is the best policy to achieve high and stable yield and is fairly promising.

Successful Field Pilot of In-Depth Colloidal Dispersion Gel (CDG) Technology in Daqing Oilfield

2006 ◽  
Vol 9 (06) ◽  
pp. 664-673 ◽  
Author(s):  
Harry L. Chang ◽  
Xingguang Sui ◽  
Long Xiao ◽  
Zhidong Guo ◽  
Yuming Yao ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Colloidal Dispersion ◽  
Oil Field ◽  
Sweep Efficiency ◽  
Profile Modification ◽  
Production Wells ◽  
Daqing Oil Field ◽  
Incremental Oil Recovery ◽  
Water Cut ◽  
Weak Gels

Summary The first large-scale colloidal dispersion gel (CDG) pilot test was conducted in the largest oil field in China, Daqing oil field. The project was initiated in May 1999, and injection of chemical slugs was completed in May 2003. This paper provides detailed descriptions of the gel-system characterization, chemical-slug optimization, project execution, performance analysis, injection facility design, and economics. The improvements of permeability variation and sweep efficiency were demonstrated by lower water cut, higher oil rate, improved injection profiles, and the increase of the total dissolved solids (TDS) in production wells. The ultimate incremental oil recovery (defined as the amount of oil recovered above the projected waterflood recovery at 98% water cut) in the pilot area would be approximately 15% of the original oil in place (OOIP). The economic analysis showed that the chemical costs were approximately U.S. $2.72 per barrel of incremental oil recovered. Results are presented in 15 tables and 8 figures. Introduction Achieving mobility control by increasing the injection fluid viscosity and achieving profile modification by adjusting the permeability variation in depth are two main methods of improving the sweep efficiency in highly heterogeneous and moderate viscous-oil reservoirs. In recent years (Wang et al. 1995, 2000, 2002; Guo et al. 2000), the addition of high-molecular-weight (MW) water-soluble polymers to injection water to increase viscosity has been applied successfully in the field on commercial scales. Weak gels, such as CDGs, formed with low-concentration polymers and small amounts of crosslinkers such as the trivalent cations aluminum (Al3+) and chromium (Cr3+) also have been applied successfully for in-depth profile modification (Fielding et al. 1994; Smith 1995; Smith and Mack 1997). Typical behaviors of CDGs and testing methods are given in the literature (Smith 1989; Ranganathan et al. 1997; Rocha et al. 1989; Seright 1994). The giant Daqing oil field is located in the far northeast part of China. The majority of the reservoir belongs to a lacustrine sedimentary deposit with multiple intervals. The combination of heterogeneous sand layers [Dykstra-Parsons (1950) heterogeneity indices above 0.5], medium oil viscosities (9 to 11 cp), mild reservoir temperatures (~45°C), and low-salinity reservoir brines [5,000 to 7,000 parts per million (ppm)] makes it a good candidate for chemical enhanced-oil-recovery processes. Daqing has successfully implemented commercial-scale polymer flooding (PF) since the early 1990s (Chang et al. 2006). Because the PF process is designed primarily to improve the mobility ratio (Chang 1978), additional oil may be recovered by using weak gels to further improve the vertical sweep. Along with the successes of PF in the Daqing oil field, two undesirable results were also observed:high concentrations of polymer produced in production wells owing to the injection of large amounts of polymer (~1000 ppm and 50% pore volume) andthe fast decline in oil rates and increase in water cuts after polymer injection was terminated. In 1997, a joint laboratory study between the Daqing oil field and Tiorco Inc. was conducted to investigate the potential of using the CDG process, or the CDG process with PF, to further improve the recovery efficiency, lower the polymer production in producing wells, and prolong the flood life. The joint laboratory study was completed in 1998 with encouraging results (Smith et al. 2000). Additional laboratory studies to further characterize the CDG gellation process, optimize the formulation, and investigate the degradation mechanisms were conducted in the Daqing field laboratories before the pilot test. A simplistic model was used to optimize the slug designs and predict incremental oil recovery. Initial designs called for a 25% pore volume (Vp) CDG slug with 700 ppm polymer and the polymer-to-crosslinker ratio (P/X) of 20 in a single inverted five-spot patten. Predicted incremental recovery was approximately 9% of OOIP.

Feasibility of Waterflooding for a Carbonate Oil Field Through Whole-Field Simulation Studies

2015 ◽  
Vol 137 (6) ◽  
Author(s):  
Wenting Yue ◽  
John Yilin Wang
Keyword(s):  
Oil Recovery ◽  
Injection Rate ◽  
Carbonate Reservoir ◽  
Oil Field ◽  
Improved Oil Recovery ◽  
Smackover Formation ◽  
Artificial Lift ◽  
Production History ◽  
Current Production ◽  
The Impact

The carbonate oil field studied is a currently producing field in U.S., which is named “PSU” field to remain anonymity. Discovered in 1994 with wells on natural flow or through artificial lift, this field had produced 17.8 × 106 bbl of oil to date. It was noticed that gas oil ratio had increased in certain parts and oil production declined with time. This study was undertaken to better understand and optimize management and operation of this field. In this brief, we first reviewed the geology, petrophysical properties, and field production history of PSU field. We then evaluated current production histories with decline curve analysis, developed a numerical reservoir model through matching production and pressure data, then carried out parametric studies to investigate the impact of injection rate, injection locations, and timing of injection, and finally developed optimized improved oil recovery (OIR) methods based on ultimate oil recovery and economics. This brief provides an addition to the list of carbonate fields available in the petroleum literature and also improved understandings of Smackover formation and similar analogous fields. By documenting key features of carbonated oil field performances, we help petroleum engineers, researchers, and students understand carbonate reservoir performances.

scholarly journals Numerical Simulation of Immiscible CO2-Assisted Gravity Drainage Process to Enhance Oil Recovery

2020 ◽  
pp. 2004-2016
Author(s):  
Dahlia Abdulhadi Al-Obaidi ◽  
Mohammed Saleh Al-Jawad
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Injection Pressure ◽  
Oil Production ◽  
Simulation Models ◽  
Injection Rate ◽  
Gravity Drainage ◽  
Effective Parameters ◽  
Water Contact ◽  
Enhance Oil Recovery

The Gas Assisted Gravity Drainage (GAGD) process has become one of the most important processes to enhance oil recovery in both secondary and tertiary recovery stages and through immiscible and miscible modes.  Its advantages came from the ability to provide gravity-stable oil displacement for improving oil recovery, when compared with conventional gas injection methods such as Continuous Gas Injection (CGI) and Water – Alternative Gas (WAG). Vertical injectors for CO2   gas were placed at the top of the reservoir to form a gas cap which drives the oil towards the horizontal oil producing wells which are located above the oil-water-contact. The GAGD process was developed and tested in vertical wells to increase oil recovery in reservoirs with bottom water drive and strong water coning tendencies. Many physical and simulation models of GAGD performance were studied at ambient and reservoir conditions to investigate the effects of this method to enhance the recovery of oil and to examine the most effective parameters that control the GAGD process.      A prototype 2D simulation model based on the scaled physical model was built for CO2-assisted gravity drainage in different statement scenarios. The effects of gas injection rate, gas injection pressure and oil production rate on the performance of immiscible CO2-assisted gravity drainage-enhanced oil recovery were investigated. The results revealed that the ultimate oil recovery increases considerably with increasing oil production rates. Increasing gas injection rate improves the performance of the process while high pressure gas injection leads to less effective gravity mediated recovery.

scholarly journals Experimental Study on Sweep Characteristics of Gas Gravity Drainage in the Interlayer Oil Reservoir

2021 ◽  
Vol 9 ◽  
Author(s):  
Hongwei Yu ◽  
Lu Wang ◽  
Daiyu Zhou ◽  
Fuyong Wang ◽  
Shi Li ◽  
...  
Keyword(s):  
Oil Recovery ◽  
High Speed ◽  
Gas Injection ◽  
Injection Rate ◽  
Physical Models ◽  
Oil Reservoirs ◽  
Movement Direction ◽  
Gravity Drainage ◽  
Gas Oil ◽  
Hydrocarbon Gas

Stable gas gravity drainage is considered an effective method to enhance oil recovery, especially suitable for deep buried, large dip angle, and thick oil reservoirs. The influence of reservoir heterogeneity on controlling the gas–oil interface and sweep characteristics of injected gas is particularly important to design reservoir development schemes. In this study, according to the interlayer characteristics of Donghe carboniferous oil reservoirs in the Tarim Basin, NW China, 2D visual physical models are established, in which the matrix permeability is 68.1 mD and average pore throat radius is 60 nm. Then, hydrocarbon gas gravity drainage simulation experiments are carried out systematically, and a high-speed camera is used to record the process of gas–oil flow and interface movement. In this experiment, the miscible zone of crude oil and hydrocarbon gas is observed for the first time. The interlayer has an obvious shielding influence, which can destroy the stability of the gas–oil interface and miscible zone, change the movement direction of the gas–oil interface, and reduce the final oil recovery after gravity drainage. The remaining oil mainly is distributed near the interlayers. The higher displacement pressure leads to increased stability of the gas–oil displacement front and later gas breakthrough, which leads to higher oil recovery. The lower gas injection rate contributes to a slower front velocity and wider miscible zone, which could delay gas breakthrough. For the immiscible gas gravity drainage, there is a critical gas injection rate, with which the oil recovery factor is the highest.

scholarly journals Waterflood optimization using an injector producer pair recovery factor, a novel approach

2021 ◽  
Vol 11 (2) ◽  
pp. 949-959 ◽  
Author(s):  
Nasser Alizadeh ◽  
Ben Salek
Keyword(s):  
Produced Water ◽  
High Water ◽  
Weighting Factor ◽  
Injection Rate ◽  
Recovery Factor ◽  
Rock Properties ◽  
Sweep Efficiency ◽  
Full Field ◽  
Novel Approach ◽  
Water Cut

AbstractThis paper presents an approach to optimize the recovery factor and sweep efficiency in a waterflooding process by automating the optimum injection rate calculations for water injectors using streamline simulation. A streamline simulator is an appropriate tool for modern waterflood management and can be used to determine the dynamic interaction between injector and producer pairs, which will vary over time based on sweep efficiency and operational changes. A streamline simulator can be used to identify injectors, which are not supporting production and contributing mainly to water producing wells. Streamlines illustrate natural fluid-flow paths in the reservoir, which are based on fluid properties, rock properties, well distribution and well rates across the reservoir. A bundle of connected streamlines can provide the oil in place between an injector/producer pair at any given time during a simulation run. Thus, the well pair recovery factors for each injector/producer pair, the produced water cut and the weighting factor for each injector are determined. Multiplying this weighting factor by the injection rates determines the new injection rate for each injector. For a well pair water cut that is lower than the average field water cut, the injection rate will be increased and vice versa. Given a finite volume of injection water, there will be a re-allocating of water from a well pair with a low recovery factor and high water cut and redistributing the water to injectors supporting low water cut producers, thus maximizing the recovery factor and reducing the field water production. The described approach is an automated procedure during the reservoir simulation run, making it appropriate for full field waterflood optimization with many injectors and producers in high-resolution heterogeneous brown reservoirs. This approach can reduce the water cut and increase the recovery factor and extend the life of the waterflooded oil fields. It was initially tested with a synthetic model and later with an actual reservoir model, which will be described in this paper.

scholarly journals Improvement of oil field development using enhanced oil recovery methods

2021 ◽  
pp. 23-28
Author(s):  
G Moldabayeva ◽  
R Suleimenova ◽  
N Buktukov ◽  
M Mergenov
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Injection ◽  
Oil Field ◽  
Water Soluble ◽  
Sweep Efficiency ◽  
Conformance Control ◽  
Water Soluble Polymer ◽  
Field Development ◽  
Water Cut

Purpose. To develop a technology to increase the oil recovery of formations using injection of polymer compositions. Methodology. For this study, practical methods were used such as enhanced oil recovery using stimulating technologies, technology using polymer systems based on a water-soluble polymer acrylamide, and emulsion-polymer technology. To achieve the conformance control, which was a prerequisite for testing, a thorough selection of wells was carried out, as well as an analysis of their hydrodynamic connection. Findings. As a result of using the method for limiting water inflows in the development of oil-bearing formations, redistribution of filtration channels, and a decrease in the production of fossil water as well as stabilisation of water cut were achieved. Originality. The scientific novelty of the study is the withdrawal of wells that are able to redistribute the volume of water injection at perforation intervals. Increased sweep efficiency and pressure at the wellhead at the beginning and at the end of the conformance control indicate a decrease in the conductivity of high-permeability formation intervals. Practical value. Application of the proposed technology for limiting water inflows will make it possible to develop low-permeability interlayers with filtration flows. The wells brought to a stable production rate during the study will ensure a decrease in formation water production and the water cut of the produced products, as well as stabilisation of the water cut over a certain period.

scholarly journals A Tracer Streamline Practice for Re-Evaluation Waterflood Pattern to Introduce a Cyclic Water Injection Scheme

2021 ◽  
Vol 6 (3) ◽  
pp. 127-136
Author(s):  
Dike Fitriansyah Putra ◽  
Lazuardhy Vozika Futur ◽  
Mursyidah Umar
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Oil Field ◽  
Sweep Efficiency ◽  
Water Influx ◽  
Injection Scheme ◽  
Pressure Water ◽  
Water Cut ◽  
Cyclic Injection ◽  
Selection Of

Waterflood introduces in the oil field a couple of years ago. Several waterflood schemes have been implemented in the fields to get the best incremental oil, such as peripheral injection, pattern waterflood, and etcetera. Many waterflood schemes are not working properly to boost the oil recovery due to unpredicted and unexpected water tide array. Then, the tracer practice started to be used for getting a better picture of the transmissibility reservoir as well as the direction of water pathway. This practice honors the parameters, such pressure, water cut, GOR, and rates. The streamline modeling is used to map the tracer, and it concludes that the selection of location of the injector should be based on the highest oil recovery achieved. Subsequently, the cyclic water injection method is one alternative. Apparently, this approach yields a quantify incremental recovery.  This research utilizes the pressure different approach to figure out the route of water in the formation. The inter-well tracer technique in this modeling study is a tool to review communication between injectors and producers in the existing pattern. Many scenario should be tried to find the best options for the new pattern opportunities. In parallel, a innovative scheme of waterflood technique should be implemented too for escalating oil recovery. The stream pathway observes a new potential of the waterflood scheme. It is called "cyclic injection" scheme.  The novelty of this approach is the ability to solve the poor sweep efficiency due to improper pathway of water influx in the oil bearing".

New Gel Aggregates To Improve Sweep Efficiency During Waterflooding

2011 ◽  
Vol 14 (01) ◽  
pp. 120-128 ◽  
Author(s):  
Guanglun Lei ◽  
Lingling Li ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Low Cost ◽  
Oil Production ◽  
High Water ◽  
Resistance Factor ◽  
Water Production ◽  
Sweep Efficiency ◽  
Low Viscosity ◽  
Productivity Decline ◽  
High Water Cut ◽  
Water Cut

Summary A common problem for oil production is excessive water production, which can lead to rapid productivity decline and significant increases in operating costs. The result is often a premature shut-in of wells because production has become uneconomical. In water injectors, the injection profiles are uneven and, as a result, large amounts of oil are left behind the water front. Many chemical systems have been used to control water production and improve recovery from reservoirs with high water cut. Inorganic gels have low viscosity and can be pumped using typical field mixing and injection equipment. Polymer or crosslinked gels, especially polyacrylamide-based systems, are mainly used because of their relatively low cost and their supposed selectivity. In this paper, microspheres (5–30 μm) were synthesized using acrylamide monomers crosslinked with an organic crosslinker. They can be suspended in water and can be pumped in sandstone formations. They can plug some of the pore throats and, thus, force injected water to change its direction and increase the sweep efficiency. A high-pressure/high-temperature (HP/HT) rheometer was used to measure G (elastic modulus) and G" (viscous modulus) of these aggregates. Experimental results indicate that these microspheres are stable in solutions with 20,000 ppm NaCl at 175°F. They can expand up to five times their original size in deionized water and show good elasticity. The results of sandpack tests show that the microspheres can flow through cores with permeability greater than 500 md and can increase the resistance factor by eight to 25 times and the residual resistance factor by nine times. The addition of microspheres to polymer solutions increased the resistance factor beyond that obtained with the polymer solution alone. Field data using microspheres showed significant improvements in the injection profile and enhancements in oil production.

Pilot Project Evaluating WAG Efficiency for Carbonate Reservoir in Eastern Siberia

2021 ◽  
Author(s):  
Valentina Zharko ◽  
Dmitriy Burdakov
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Pilot Project ◽  
Carbonate Reservoir ◽  
Recovery Factor ◽  
Eastern Siberia ◽  
Water Cut ◽  
Wag Injection ◽  
Injection Rates

Abstract The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

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