scholarly journals Scaling tendency prediction in water injection well of K2 formation of C68 block

2021 ◽  
Vol 300 ◽  
pp. 02012
Author(s):  
Zhitao Yan ◽  
Ruohan Hu ◽  
Fengyan Li ◽  
Shouxing Kang ◽  
Liping Zhang
Keyword(s):  
Water Injection ◽  
Petroleum Industry ◽  
Injection Rate ◽  
Water Flooding ◽  
Injection Wells ◽  
Injection Water ◽  
Water Rate ◽  
Temperature And Pressure ◽  
Oilfield Development ◽  
Rate Requirement

The K2 formation of C68 block is explored by injecting water to maintain formation pressure, but the continuous decrease of injection rate significantly reduces oil production. Therefore, it is important to predict scaling tendency of injected water in the formation. Firstly, ion composition of formation water and injected water was tested according to recommended practices in petroleum industry. Then, wellbottom temperature distribution of injection wells was simulated under injection water rate requirement of oilfield development. Furthermore, based on the “Oddo-Tomson” prediction model of inorganic scale, the scaling trend of water flooding in K2 formation is predicted according to the possible temperature and pressure. The research indicates that sulfate scale cannot be formed in C68 block and there is a slight possibility of carbonate scaling, which provides a basis to select the correct stimulation technology for increasing production.

A Model for Water Injection Into Frac-Packed Wells

2010 ◽  
Vol 13 (03) ◽  
pp. 449-464 ◽  
Author(s):  
Ajay Suri ◽  
Mukul M. Sharma
Keyword(s):  
Water Injection ◽  
Horizontal Stress ◽  
Injection Rate ◽  
Injection Wells ◽  
Solids Concentration ◽  
Sand Control ◽  
Injection Water ◽  
Large Injection ◽  
Minimum Horizontal Stress ◽  
Injection Rates

Summary Frac packs are increasingly being used for sand control in injection wells in poorly consolidated reservoirs. This completion allows for large injection rates and longer injector life. Many of the large offshore developments in the Gulf of Mexico and around the world rely on these completions for waterflooding and pressure maintenance. The performance of these injectors is crucial to the economics of the project because well intervention later in the life of the field is expensive and undesirable. For the first time, we present a model for water injection in frac-packed wells. The frac pack and the formation are plugged because of the deposition of particles from the injected water, and their effective permeability to water is continuously reduced. However, as the bottomhole pressure (BHP) reaches the frac-pack widening pressure, the frac-pack width increases and a channel that accommodates additional injected particles is created. Injectivity depends on the interstitial velocity of the injected water in the frac pack, volume concentration of the solids in the injected water, injection rate, injection-water temperature, size of proppants in the frac pack, width and length of the frac pack, and the initial minimum horizontal stress. In case of frac packs with large proppant size and high injection rates, the plugging of the frac pack is found to be negligible except in the building of a filter cake at the frac-pack walls. In the case of narrow frac packs with small proppant, significant plugging is expected, which leads to sharp permeability decline of the frac pack and a rapid rise in the BHP. The long-term injectivity of a frac-packed injector depends primarily on the filtration coefficient value of the frac pack, solids concentration in the injected water, and the injection rate. Frac packs are expected to maintain higher injectivities compared to any other completions such as openhole, cased-hole, perforated, or gravel packs.

scholarly journals Polymer gels for controlling water thief zones in injection wells

2012 ◽  
Vol 5 (1) ◽  
pp. 37-44 ◽  
Author(s):  
Gustavo-Adolfo Maya-Toro ◽  
Rubén-Hernán Castro-García ◽  
Zarith del Pilar Pachón-Contreras. ◽  
Jose-Francisco Zapata-Arango
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Injection Wells ◽  
Recovery Processes ◽  
Injection Water ◽  
Secondary Oil Recovery ◽  
High Concentrations ◽  
Low Efficiency ◽  
Hydrolyzed Polyacrylamide ◽  
Positive Results

Oil recovery by water injection is the most extended technology in the world for additional recovery, however, formation heterogeneity can turn it into highly inefficient and expensive by channeling injected water. This work presents a chemical option that allows controlling the channeling of important amounts of injection water in specific layers, or portions of layers, which is the main explanation for low efficiency in many secondary oil recovery processes. The core of the stages presented here is using partially hydrolyzed polyacrylamide (HPAM) cross linked with a metallic ion (Cr+3), which, at high concentrations in the injection water (5000 – 20000 ppm), generates a rigid gel in the reservoir that forces the injected water to enter into the formation through upswept zones. The use of the stages presented here is a process that involves from experimental evaluation for the specific reservoir to the field monitoring, and going through a strict control during the well intervention, being this last step an innovation for this kind of treatments. This paper presents field cases that show positive results, besides the details of design, application and monitoring.

scholarly journals Increasing Efficiency of Field Water Re-Injection during Water-Flooding in Mature Hydrocarbon Reservoirs: A Case Study from the Sava Depression, Northern Croatia

2020 ◽  
Vol 12 (3) ◽  
pp. 786 ◽  
Author(s):  
Tomislav Malvić ◽  
Josip Ivšinović ◽  
Josipa Velić ◽  
Jasenka Sremac ◽  
Uroš Barudžija
Keyword(s):  
Water Injection ◽  
Inverse Distance Weighting ◽  
Hydrocarbon Reservoirs ◽  
Water Flooding ◽  
Injection Wells ◽  
Weighting Method ◽  
Hydrocarbon Production ◽  
Recovery Method ◽  
Distance Weighting ◽  
Inverse Distance

The authors analyse the process of water re-injection in the hydrocarbon reservoirs/fields in the Upper Miocene sandstone reservoirs, located in the western part of the Sava Depression (Croatia). Namely, this is the “A” field with “L” reservoir that currently produces hydrocarbons using a secondary recovery method, i.e., water injection (in fact, re-injection of the field waters). Three regional reservoir variables were analysed: Porosity, permeability and injected water volumes. The quantity of data was small for porosity reservoir “L” and included 25 points; for permeability and injected volumes of water, 10 points each were measured. This study defined selection of mapping algorithms among methods designed for small datasets (fewer than 20 points). Namely, those are inverse distance weighting and nearest and natural neighbourhood. Results were tested using cross-validation and isoline shape recognition, and the inverse distance weighting method is described as the most appropriate approach for mapping permeability and injected volumes in reservoir “L”. Obtained maps made possible the application of the modified geological probability calculation as a tool for prediction of success for future injection (with probability of 0.56). Consequently, it was possible to plan future injection more efficiently, with smaller injected volumes and higher hydrocarbon recovery. Prevention of useless injection, decreasing number of injection wells, saving energy and funds invested in such processes lead to lower environmental impact during the hydrocarbon production.

Reinforcement Learning From Pixels: Waterflooding Optimization

2020 ◽  
Author(s):  
Ruslan Miftakhov ◽  
Igor Efremov ◽  
Abdulaziz S. Al-Qasim
Keyword(s):  
Reinforcement Learning ◽  
Net Present Value ◽  
Vertical Section ◽  
Water Injection ◽  
Petroleum Industry ◽  
Injection Pressure ◽  
Injection Rate ◽  
Simulation Engine ◽  
First Case ◽  
The Impact

Abstract The application of Artificial Intelligence (AI) methods in the petroleum industry gain traction in recent years. In this paper, Deep Reinforcement Learning (RL) is used to maximize the Net Present Value (NPV) of waterflooding by changing the water injection rate. This research is the first step towards showing that the use of pixel information for reinforcement learning provides many advantages, such as a fundamental understanding of reservoir physics by controlling changes in pressure and saturation without directly accounting for the reservoir petrophysical properties and wells. The optimization routine based on RL by pixel data is tested on the 2D model, which is a vertical section of the SPE 10 model. It has been shown that RL can optimize waterflooding in a 2D compressible reservoir with the 2-phase flow (oil-water). The proposed optimization method is an iterative process. In the first few thousands of updates, NPV remains in the baseline since it takes more time to converge from raw pixel data than to use classical well production/injection rate information. RL optimization resulted in improving the NPV by 15 percent, where the optimum scenario shows less watercut values and more stable production in contrast to baseline optimization. Additionally, we evaluated the impact of selecting the different action set for optimization and examined two cases where water injection well can change injection pressure with a step of 200 psi and 600 psi. The results show that in the second case, RL optimization is exploiting the limitation of the reservoir simulation engine and tries to imitate a cycled injection regime, which results in a 7% higher NPV than the first case.

The Coupling Model of Wellbore Conduit Flow, Throttled Flow and Formation Seepage in Water Injection Wells

2012 ◽  
Vol 594-597 ◽  
pp. 2486-2489
Author(s):  
Bao Jun Liu ◽  
Hai Xia Shi ◽  
Yun Sheng Cai
Keyword(s):  
Flow Rate ◽  
Water Injection ◽  
Coupling Model ◽  
Water Flooding ◽  
Finite Radius ◽  
Injection Wells ◽  
Conduit Flow ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Low Efficiency

Separate layer water flooding is adopted in most oilfields in China and the injection flow rate is controlled by the diameter of water nozzle of each layer. In order to ensure the effect of water injection, applicable water nozzles need to be adjusted to meet the requirements of injection flow rate. The adjustment is commonly realized according to experience, which leads to long adjustment time and low efficiency. To solve this problem, the coupling model of wellbore conduit flow, throttled flow and formation seepage was established based on theoretical analysis, which could provide theoretical basis for water nozzles adjustment. In the model, the Bernoulli Equation was adopted to analyze wellbore conduit flow; indoor experiments were done to research throttled flow; the research object of the seepage was finite radius well in homogeneous infinite formation.

scholarly journals Modeling Transient Flow in CO2 Injection Wells by Considering the Phase Change

Processes ◽  
2021 ◽  
Vol 9 (12) ◽  
pp. 2164
Author(s):  
Nian-Hui Wan ◽  
Li-Song Wang ◽  
Lin-Tong Hou ◽  
Qi-Lin Wu ◽  
Jing-Yu Xu
Keyword(s):  
Transient Flow ◽  
Maximum Error ◽  
Injection Rate ◽  
Co2 Injection ◽  
Injection Wells ◽  
Transient Model ◽  
Pressure Profiles ◽  
Wellbore Temperature ◽  
Temperature And Pressure

A transient model to simulate the temperature and pressure in CO2 injection wells is proposed and solved using the finite difference method. The model couples the variability of CO2 properties and conservation laws. The maximum error between the simulated and measured results is 5.04%. The case study shows that the phase state is primarily controlled by the wellbore temperature. Increasing the injection temperature or decreasing the injection rate contributes to obtaining the supercritical state. The variability of density can be ignored when the injection rate is low, but for a high injection rate, ignoring this may cause considerable errors in pressure profiles.

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.

Overview the 5 Years Experience of Intelligent Separate-Layer Injection Technology in B Offshore Oilfield

2021 ◽  
Author(s):  
Yigang Liu ◽  
Zheng Chen ◽  
Xianghai Meng ◽  
Zhixiong Zhang ◽  
Jian Zou ◽  
...  
Keyword(s):  
Short Circuit ◽  
Water Injection ◽  
Operation Time ◽  
Water Flooding ◽  
Internal Diameter ◽  
Injection Wells ◽  
Mode Water ◽  
Separate Layer ◽  
Injection Technology ◽  
Large Flow

Abstract Nowadays intelligent injection is considered as a new frontier for offshore oilfield. In order to improve the water injection indicators such as allocation frequency and qualification rate, intelligent separate-layer injection technology (ISIT) was researched, deployed and optimized in B offshore oilfield from 2015. In the course of 5 years’ project operation, some experience of success or failure was achieved. B offshore oilfield is the largest offshore oilfield in China with 33 water flooding oilfields and more than 800 water injection wells. With the continuous development, the problem of injection management mainly reflected in the contradiction between increasing demand of allocation and limited operation time and space was exposed. Two kinds of ISIT, cable implanted intelligent separate-layer injection technology(CISIT) and wireless intelligent separate-layer injection technology(WISIT), were deployed to solve the above problem. CISIT controlled the distributor downhole by electricity while WISIT controlled the distributor downhole by pressure pulse. By the use of ISIT, downhole nozzle's action, packer testing and downhole data monitoring could be remotely controlled on the ground. During the 5 years’ test, ISIT was optimized from the field breakdown including large flow range flowing test, cable protection project, efficient coding mode, water seepage resistance and so on. With the continuous optimization and quality control improvement, ISIT has overcome many problems, such as downhole short circuit and communication loss, and is becoming more stable and reliable. At present, ISIT can meet the needs of large flow injection(max 800m3/d per layer) and can adapt to the high frequency of acidizing and fracturing in offshore oilfield. The failure rate of ISIT has dropped to nearly 20% in 2020. As of December 2020, ISIT has formed series products for different internal diameter wells and applied in 156 water injection wells in B offshore oilfield. The average allocation frequency has increased from less than one time to 2 times per year. Through the application of ISIT, B offshore oilfield has accumulatively saved more than 2100 days of platform occupation and more than 73 million RMB yuan of allocation cost. The use of ISIT makes B offshore oilfield's injection become more efficient and intelligent. The 5 years’ experience of ISIT applicationin B offshore oilfield has a fairly referential significance for other offshore oilfields.

The Research of Layer System Subdivision and Adjustment Methods in YSL Block of the Low Permeability Reservoirs

2013 ◽  
Vol 274 ◽  
pp. 153-156
Author(s):  
Rong Hua Li ◽  
Jun Ting Zhang ◽  
Cheng Lin Zhang ◽  
Huan Huan Zhang ◽  
Peng Qu
Keyword(s):  
Water Injection ◽  
Oil Field ◽  
Thin Layers ◽  
Water Flooding ◽  
Low Permeability ◽  
Layer System ◽  
Oil Distribution ◽  
Major Adjustment ◽  
Low Permeability Reservoirs ◽  
Oilfield Development

Layer system subdivision and adjustment is applied in oilfield development to ease the contradiction in inner-layer and interlayer and implement separated layer water flooding well, which is a major adjustment measure to improve developing effects. YSL is a typical low-permeability oil field, whose petrophysics is poor, and which exist many problems, such as apparent contradictions between layers, and poor development effects through separated zone water injection and so on. In this article, the thickness of barriers, injection profile, permeability contrast and remaining oil distribution are analyzed comprehensively. So a reasonable method is also proposed. Much weakness that factors are not comprehensive in adjustment method and that the problems in the development process are not accurately reflected is overcome, which exists in the past methods. The adjustment means can utilize poor thin layers better, reduce invalid water injection and ease the contradictions between layer, and oilfield development effects are improved eventually. It is a reference and guidance for other blocks or oilfield which exist the same problems.

A Method to Determine the Optimal Water Injection Intensity Based on Oil Production Rate and Water Cut

2012 ◽  
Vol 594-597 ◽  
pp. 2442-2445 ◽  
Author(s):  
Ji Cheng Zhang ◽  
Ying Jia ◽  
Xiao Na Cui
Keyword(s):  
Production Rate ◽  
Water Injection ◽  
Oil Production ◽  
Water Flooding ◽  
Water Intensity ◽  
Water Cut ◽  
Relationship Of ◽  
The Relationship ◽  
Oilfield Development ◽  
Zone Water

Water injection is one of the important ways to maintain reservoir pressure and improving the oilfield development effect. And separate zone water injection is the main technology in water flooding oilfield. The optimal water intensity which has been allocated plays an important role in all kinds of reservoir. This paper proposed a method to optimize the water injection intensity based on oil production rate and water cut. Conceptual model was constructed on the basis of real reservoir. By numerical simulation, a chart board was derived which describes the relationship of water injection intensity versus oil production rate and water cut. Using this chart, we can determine the optimal water injection intensity on different oil production rate and water cut.

Sign in / Sign up

Export Citation Format

Share Document