Challenges and Lesson Learnt of 1st IWAG Implementation in a Mature Oil Field, East Malaysia

2021 ◽  
Author(s):  
Kok Liang Tan ◽  
Sulaiman Sidek ◽  
Syakirin M. Nazri ◽  
Haziqah Hamzah
Keyword(s):  
Performance Test ◽  
Gas Injection ◽  
Water Injection ◽  
Pressure Gauge ◽  
Management Plan ◽  
Injection Rate ◽  
Oil Field ◽  
Cycle Duration ◽  
Fluid Temperature ◽  
Tertiary Recovery

Abstract Immiscible Water Alternating Gas (iWAG) scheme was adopted in Echo field, offshore Sarawak Malaysia, to increase recovery factor of the matured oil reservoir after more than two (2) decades of peripheral water injection. It was implemented through four (4) horizontal wells located at reservoir’s eastern and western flanks. Since the commencement of iWAG injection, multiple challenges occured interrupting the stable injection that halting the success of this integrated mega scale project. It started with prolonged iWAG performance test run due to surface constraint, measurement and well issues on executing switching test, followed with low injectivity during switching operation. Subsequently, injectivity issues occured in the gas phase after several injection cycles. In addition to that, injector wells facing high downtime due to surface facilities and well integrity issues, causing low injection rates and unavailability to meet cycle volume within the stipulated duration. Reactivation of iWAG benefiter wells also prove to be challenging due to wells have been idle for a long time and multiple interventions required to revive the well. Injection data for both gas and water phase were analysed to improve iWAG operating procedure and understand the wells performance. INJ-J2 was installed with temporary pressure gauge during the water to gas switching, while the other two (2) wells are equipped with Permanent Downhole Gauge (PDG) to monitor the well injectivity. Application of non-intrusive flowmeter was also proven useful in calibrating the Flow Transmitter (FT) for both water and gas injectors, ensuring the accuracy and precision in the water and gas injection measurement. Besides that, fluid temperature trending was referred to validate on the meter measurement. Low injection rate compared to original plan were reviewed with the Reservoir Management Plan (RMP). Several approaches are implemented in order to achieve the iWAG RMP target and idle well reactivation. Analysis of injection data showed that gas injectivity issue occurred after the water to gas switching cycle. Injectivity improves slightly after long duration of continuous gas injection and applying higher Tubing Head Pressure (THP), unfortunately some wells remain with low injectivity because of insufficient discharge pressure to push the water from the near-wellbore deep into the reservoir to improve injection. Low injection rate issue is mitigated by extending injection cycle duration in order to meet the RMP cycle volume. Besides that, wells are normally injected with higher injection rate to cater for the high downtime. Both gas and water injection are balanced to ensure that the wells reached their cycle volume at similar duration. With limited new field discovery by the Operator, tertiary recovery on the mature field is inevitable. However, there is less implementation of iWAG in offshore field. Through this paper, authors wish to provide insights and lesson learnt for others when planning for iWAG tertiary recovery, taking account of various challenges faced.

scholarly journals Experimental Study on Enhanced Oil Recovery by Nitrogen-Water Alternative Injection in Reservoir with Natural Fractures

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Xiang Li ◽  
Yuan Cheng ◽  
Wulong Tao ◽  
Shalake Sarulicaoketi ◽  
Xuhui Ji ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Water Flooding ◽  
Orthogonal Experimental Design ◽  
Fractured Reservoir ◽  
Natural Fractures ◽  
Nitrogen Injection

The production of a low permeability reservoir decreases rapidly by depletion development, and it needs to supplement formation energy to obtain stable production. Common energy supplement methods include water injection and gas injection. Nitrogen injection is an economic and effective development method for specific reservoir types. In order to study the feasibility and reasonable injection parameters of nitrogen injection development of fractured reservoir, this paper uses long cores to carry out displacement experiment. Firstly, the effects of water injection and nitrogen injection development of a fractured reservoir are compared through experiments to demonstrate the feasibility of nitrogen injection development of the fractured reservoir. Secondly, the effects of gas-water alternate displacement after water drive and gas-water alternate displacement after gas drive are compared through experiments to study the situation of water injection or gas injection development. Finally, the reasonable parameters of nitrogen gas-water alternate injection are optimized by orthogonal experimental design. Results show that nitrogen injection can effectively enhance oil production of the reservoir with natural fractures in early periods, but gas channeling easily occurs in continuous nitrogen flooding. After water flooding, gas-water alternate flooding can effectively reduce the injection pressure and improve the reservoir recovery, but the time of gas-water alternate injection cannot be too late. It is revealed that the factors influencing the nitrogen-water alternative effect are sorted from large to small as follows: cycle injected volume, nitrogen and water slug ratio, and injection rate. The optimal cycle injected volume is around 1 PV, the nitrogen and water slug ratio is between 1 and 2, and the injection rate is between 0.1 and 0.2 mL/min.

Laboratory Evaluation Experiment for Adaptability Analysis of Nitrogen Injection in Yanchang Oil Field

2021 ◽  
Author(s):  
Jiaxi Gao ◽  
Yuedong Yao ◽  
He Bao ◽  
Jinjiang Shen
Keyword(s):  
Field Test ◽  
Formation Energy ◽  
Gas Injection ◽  
Water Injection ◽  
Oil Field ◽  
Injection System ◽  
Laboratory Evaluation ◽  
Energy Supplement ◽  
Nitrogen Injection ◽  
Wide Range

Abstract: Yanchang Oilfield conducts systematic research on nitrogen injection to enhance oil recovery. Through the research of this project, the energy supplement method of horizontal wells suitable for the study area is determined, and its injection system and process parameters are optimized and determined. The optimal energy replenishment method selected by the mine field test achieves the following economic and technical indicators: Provide a nitrogen suitability evaluation plan; Complete the nitrogen flooding matching process design of the target well; Complete the design of the injection-production plan for the target well; Compare with other energy supplement methods. Through the analysis of two supplementary energy methods of water injection and gas injection in indoor and similar reservoirs, the following understandings have been obtained: (1) Nitrogen is insoluble in water, slightly soluble in oil, good swelling, large elastic energy, is an inert gas, exists widely in the atmosphere, inexhaustible, inexhaustible, has a wide range of sources. (2) the recovery rate of nitrogen flooding is significantly higher than that of water flooding. (3) The field test results of water injection and nitrogen test in similar reservoirs show that the supplementary formation energy of nitrogen injection is suitable for the later development of Chang 64 and Chang 71 in the Haobasi oil field. (4) Compared with deep ultra-low permeability reservoirs, it is more economical to use nitrogen to supplement formation energy and change oil. The rate is higher. From the above analysis, it can be seen that the supplementary energy of Chang 64 and Chang 71 reservoirs in the Haobasi oil area should be nitrogen injection as the main supplement, and water injection as a supplement. Gas/water alternate injection is used to adjust the gas injection profile to slow down the escape of injected nitrogen. . Although water injection supplements the formation energy with greater uncertainty, it can be used as a technical means of fluidity control in the gas injection process and is relatively economical.

scholarly journals Simulation Study of Allied In-Situ Injection and Production for Enhancing Shale Oil Recovery and CO2 Emission Control

Energies ◽  
2019 ◽  
Vol 12 (20) ◽  
pp. 3961
Author(s):  
Haiyang Yu ◽  
Songchao Qi ◽  
Zhewei Chen ◽  
Shiqing Cheng ◽  
Qichao Xie ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Co2 Emission ◽  
Gas Injection ◽  
Water Injection ◽  
Oil Production ◽  
Injection Rate ◽  
Oil Reservoirs ◽  
Shale Oil ◽  
Shale Oil Reservoirs

The global greenhouse effect makes carbon dioxide (CO2) emission reduction an important task for the world, however, CO2 can be used as injected fluid to develop shale oil reservoirs. Conventional water injection and gas injection methods cannot achieve desired development results for shale oil reservoirs. Poor injection capacity exists in water injection development, while the time of gas breakthrough is early and gas channeling is serious for gas injection development. These problems will lead to insufficient formation energy supplement, rapid energy depletion, and low ultimate recovery. Gas injection huff and puff (huff-n-puff), as another improved method, is applied to develop shale oil reservoirs. However, the shortcomings of huff-n-puff are the low sweep efficiency and poor performance for the late development of oilfields. Therefore, this paper adopts firstly the method of Allied In-Situ Injection and Production (AIIP) combined with CO2 huff-n-puff to develop shale oil reservoirs. Based on the data of Shengli Oilfield, a dual-porosity and dual-permeability model in reservoir-scale is established. Compared with traditional CO2 huff-n-puff and depletion method, the cumulative oil production of AIIP combined with CO2 huff-n-puff increases by 13,077 and 17,450 m3 respectively, indicating that this method has a good application prospect. Sensitivity analyses are further conducted, including injection volume, injection rate, soaking time, fracture half-length, and fracture spacing. The results indicate that injection volume, not injection rate, is the important factor affecting the performance. With the increment of fracture half-length and the decrement of fracture spacing, the cumulative oil production of the single well increases, but the incremental rate slows down gradually. With the increment of soaking time, cumulative oil production increases first and then decreases. These parameters have a relatively suitable value, which makes the performance better. This new method can not only enhance shale oil recovery, but also can be used for CO2 emission control.

Applying Analytic Hierarchy Process to Determine Separate Layer Water Injection Rate of Single Well

2013 ◽  
Vol 734-737 ◽  
pp. 1354-1357
Author(s):  
Wu Yi Shan ◽  
Wei Lin Cui ◽  
Yong Sheng Li
Keyword(s):  
Analytic Hierarchy Process ◽  
Water Injection ◽  
Injection Rate ◽  
Oil Field ◽  
Analytic Hierarchy ◽  
Practical Applications ◽  
Separate Layer ◽  
Single Well ◽  
Water Cut ◽  
Hierarchy Process

The separate layer water injection rate determines the result of water injection. In the past, in order to inject a proper amount of water into different intervals, most of the time people would rely on their experiences. By employing this method, the amount of work was enormous and the result was not necessarily accurate. In this paper, five factors that would affect the water injection rate are taken into consideration, such as, thickness of the main well, the connected thickness, permeability, number of connected wells and oil saturation. A method of determining the proper water injection rate of single wells based on analytic hierarchy process is proposed. This method has been proven to be simple and accurate, the test result of a mathematical model also shows it fits the requirements of the oil field exploitation with current water cut and it is of great value to practical applications.

Applying BP Neural Network to Determine Proper Water Injection Intensity of Water Drive Oil Field

2013 ◽  
Vol 734-737 ◽  
pp. 1358-1361
Author(s):  
Wu Yi Shan ◽  
Wei Lin Cui ◽  
Yong Sheng Li
Keyword(s):  
Neural Network ◽  
Neural Network Model ◽  
Bp Neural Network ◽  
Water Injection ◽  
Injection Rate ◽  
Influential Factors ◽  
Oil Field ◽  
Well Water ◽  
Network Data ◽  
Single Well

In this paper, combining previous research on methods of determining water injection rate, dividing coefficient is introduced into this process. Influential factors of water injection rate are also taken into consideration. Based on those theories mentioned above, an analysis on determining dividing coefficient is made by applying BP neural network. Data from one particular year of exploitation was chosen to build up a neural network model between the dividing coefficient and other factors to determine the dividing coefficient, and then single well water injection rate was determined.

scholarly journals A Novel Method for Improving Water Injectivity in Tight Sandstone Reservoirs

2014 ◽  
Vol 2014 ◽  
pp. 1-7 ◽  
Author(s):  
Mohamad Yousef Alklih ◽  
Bisweswar Ghosh ◽  
Emad Waleed Al-Shalabi
Keyword(s):  
Ph Monitoring ◽  
Water Injection ◽  
Electrical Current ◽  
Injection Rate ◽  
Size Exclusion ◽  
Voltage Gradient ◽  
Fluid Temperature ◽  
Tight Sandstone ◽  
Electrokinetic Effect ◽  
Core Permeability

Applicability of electrokinetic effect in improving water injectivity in tight sandstone is studied. DC potential and injection rate are varied for optimization and determination of their individual impact on clay discharge and movement. The liberated clays were characterized through size exclusion microfiltration and ICP-MS analysis. Real time temperature and pH monitoring were also informative. Results showed that severalfold (up to 152%) apparent increase of core permeability could be achieved. Some of the experiments were more efficient in terms of dislodgement of clays and enhanced stimulation which is supported by produced brines analysis with higher concentration of clay element. The results also showed larger quantity of clays in the produced brine in the initial periods of water injection followed by stabilization of differential pressure and electrical current, implying that the stimulation effect stops when the higher voltage gradient and flow rates are no more able to dislodge remaining clays. Additionally, fluid temperature measurement showed an increasing trend with the injection time and direct proportionality with the applied voltage. The basic theory behind this stimulation effect is predicted to be the colloidal movement of pore lining clays that results in widening of pore throats and/or opening new flow paths.

Design of Simultaneous Enhanced Oil Recovery and Carbon Dioxide Storage With Potential Application to Offshore Trinidad

SPE Journal ◽  
2013 ◽  
Vol 18 (02) ◽  
pp. 345-354 ◽  
Author(s):  
Lorraine E. Sobers ◽  
Martin J. Blunt ◽  
Tara C. LaForce
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Injection Rate ◽  
Gas Composition ◽  
Reservoir Properties ◽  
Injection Strategy ◽  
Oil Density ◽  
Carbon Dioxide Co2

Summary We developed an injection strategy to recover moderately heavy oil and store carbon dioxide (CO2) simultaneously. Our compositional simulations are founded on pressure/volume/temperature- (PVT-) matched properties of oil found in an unconsolidated deltaic sandstone deposit in the Gulf of Paria, offshore Trinidad. In this region, oil density ranges between 940 and 1010 kg/m3 (9 to 18°API). We use countercurrent injection of gas and water to improve reservoir sweep and trap CO2 simultaneously; water is injected in the upper portion of the reservoir, and gas is injected in the lower portion. The two water-injection rates investigated, 100 and 200 m3/d, correspond to the water-gravity numbers 6.3 to 3.1 for our reservoir properties. We applied this injection strategy using vertical producers with two injection configurations: single vertical injector and a pair of horizontal parallel laterals in a simplified representation of the unconsolidated Forest sand found offshore Trinidad. Twelve simulation runs were conducted, varying injection-gas composition for miscible- and immiscible-gas drives, water-injection rate, and injection-well orientation. Our results show that water-over-gas injection can realize oil recoveries ranging from 17 to 30%. In each instance, more than 50% of injected CO2 remained in the reservoir, with less than 15% of the retained CO2 in the mobile phase.

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.

CALCULATION OF OPTIMAL INJECTION RATE FOR DISPERSED WATERFLOODING SYSTEM

2017 ◽  
pp. 63-67
Author(s):  
L. A. Vaganov ◽  
A. Yu. Sencov ◽  
A. A. Ankudinov ◽  
N. S. Polyakova
Keyword(s):  
Injection Rate ◽  
Oil Field ◽  
Injection Well ◽  
Water Migration ◽  
Mutual Location ◽  
Optimal Injection ◽  
Technical Measures ◽  
Injection Rates

The article presents a description of the settlement method of necessary injection rates calculation, which is depended on the injected water migration into the surrounding wells and their mutual location. On the basis of the settlement method the targeted program of geological and technical measures for regulating the work of the injection well stock was created and implemented by the example of the BV7 formation of the Uzhno-Vyintoiskoe oil field.

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.

Sign in / Sign up

Export Citation Format

Share Document