OPTIONS OF PULSE NON-STATIONARY WATER FLOODING IN BLOCK SYSTEMS OF DEVELOPMENT

2017 ◽  
pp. 99-103 ◽  
Author(s):  
M. Ya. Habibullin ◽  
R. I. Suleymanov ◽  
L. Z. Zaynagalina ◽  
V. A. Petrov
Keyword(s):  
Water Injection ◽  
Filtration Velocity ◽  
Maximum Distance ◽  
Water Flooding ◽  
Relative Location ◽  
Single Group ◽  
Injection Wells ◽  
Cutting Line ◽  
Mode Of Operation ◽  
Production Wells

In the block systems of water flooding the features of relative location of injection and production wells allow for the variety of options for changing the mode of operation (single, group, block, etc.). The greatest overall effect of the change in filtration velocity at the cutting line, and hence also the effect of pulsed non-stationary flooding, is achieved by alternate stopping of wells. The maximum distance between the injection wells, the mode of operation of which can be changed at the same time, is limited by the duration of the stop and subsequent water injection. Thus, if the duration of half cycles is the same, then this ratio is equal to two, that is the wells in a row should be stopped through one row.

scholarly journals Streamline simulation study on recovery of oil by water flooding: A real case study on Haripur field

2016 ◽  
Vol 28 (1) ◽  
pp. 61-72
Author(s):  
Mohammad Amirul Islam ◽  
ASM Woobaidullah ◽  
Badrul Imam
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Oil Production ◽  
Water Flooding ◽  
Present Condition ◽  
Optimum Number ◽  
Injection Wells ◽  
Reservoir Performance ◽  
Production Wells ◽  
Head Pressure

Haripur field is the first oil producing field in Bangladesh. The field produced approximately 0.53 MMSTB of oil from the well No. SY-7. The oil production began in 1987 and terminated in 1994. All of the oil was produced by the reservoir own energy from the depth of 2030 meter. Recent investigation and study have revealed that approximately 31 MMSTB Oil is remaining in that formation as validated by the reservoir performance based study i.e. oil production rate and tube head pressure history matching. At present condition, the reservoir has no pressure energy to lift the oil to surface as it requires minimum 1500 psi pressure, so it needs pressure energy to lift the oil to surface. Among the recent developed technologies water injection is one of the best methods to sweep oil towards the production well from the injection well as well as to provide sufficient pressure for lifting. In this study we proposed design for optimum waterflooding pattern and defined optimum number of injection and production wells. In addition the production and injection rates are optimized along with selection of the best placement of production and injection wells and their life.Bangladesh J. Sci. Res. 28(1): 61-72, June-2015

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.

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 Design method and application of accurate adjustment scheme for water injection wells around adjustment wells

2021 ◽  
Author(s):  
Tongchun Hao ◽  
Liguo Zhong ◽  
Jianbin Liu ◽  
Xiaodong Han ◽  
Tianyin Zhu ◽  
...  
Keyword(s):  
Production Efficiency ◽  
Design Method ◽  
Water Injection ◽  
Oil Field ◽  
Productivity Index ◽  
Injection Wells ◽  
Wellhead Pressure ◽  
Production Wells ◽  
Drilling Operations ◽  
The Impact

AbstractAffected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut-in method is to close all water injection wells around the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method uses water injection index and liquid productivity index as target parameters to analyze the correlation between injection and production wells. Select water injection wells with a high correlation and combine other parameters such as wellhead pressure and pressure recovery speed to design accurate adjustment schemes. Low-correlation wells do not take shut-in measures. This method was applied to 20 infill adjustment wells in the Penglai Oilfield. The correlation between injection and production wells was calculated using the data more than 500 injection wells and production wells. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000 m3. This method achieves accurate adjustment for water injection wells that are high correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.

Comparison of Water Treatment Plant and Water Source Well: Field Evaluation of Waterflooding Project in Shushufindi-Aguarico Field

2021 ◽  
Author(s):  
Oki Maulidani ◽  
Veronica Maldonado ◽  
Juan Gallardo ◽  
Victoria Zurita ◽  
Cristian Giol ◽  
...  
Keyword(s):  
Water Treatment ◽  
Water Injection ◽  
Treatment Plant ◽  
Water Reservoir ◽  
Field Evaluation ◽  
Water Treatment Plant ◽  
Water Source ◽  
Operational Cost ◽  
Injection Wells ◽  
Production Wells

Abstract Waterflooding project has been implemented in Shushufindi-Aguarico mature field since late 2014. Having a compatible and cost-effective injected water is one of the key elements to ensure the success of this project. In perspective, water treatment plant was constructed in 2014 during pilot stage while water sources wells were completed in 2019 as an alternative source of injected water at the expansion stage of waterflooding project. This paper presents the comparison between both systems used as part of the water injection strategy: the Water Injection Plant (WIP) and Water Producer Wells (WPW). A complete system of water treatment plant is located in one of the production stations. The process basically starts by collecting water from production wells and workovers then treating it mechanically using a flotation unit and chemically to remove solid as well as oil contents. The water is then injected into injection wells with the help of horizontal pumping system (HPS). In the system of water source wells, two wells were converted to produce water from Hollin water reservoir utilizing electrical submersible pumps (ESP). The water is directly injected without any treatment into injection wells given the analysis of its fluid properties. The initial investment for water treatment plant is four times compared to water source well providing equal injection capacity where the operational cost per barrel of injected water is similar. The operational cost for water treatment plant refers to surface facilities maintenance and daily chemical consumption while for water source well it refers to associated cost of ESP reparation and workover operation. The average run-life of the water source wells in Ecuador Oriente basin is 1,200 days. The biggest challenge of water treatment plant is dealing with solid content whereas for water source well is on how to ensure integrity of the well and the flowline system in the high temperature and CO2 environment. Continuous improvements have been performed to address these challenges such as chemical treatment adjustments, real-time surveillance of injection wells, and modification of flowline system. Water treatment plant not only provides compatible water for injection wells but also supports water handling capacity as it utilizes water from production wells. In the other hand, compatible and clean water from Hollin water reservoir is the main benefit of water source wells. This paper will outline the pros and cons of water treatment plant and water source well based on field evaluation in Shushufindi-Aguarico field. It outlines the operational experience and lessons learned that can be used as a guide and reference when evaluating water sources for a waterflooding strategy. Economical analysis as well as continuous improvement will also be presented in this paper to deliver an integrated analysis.

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 Maureen Field, Block 16/29a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 347-352 ◽  
Author(s):  
P. L. Cutts
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Upper Jurassic ◽  
Reservoir Properties ◽  
Injection Wells ◽  
The North ◽  
Clay Shales ◽  
Gravity Flows ◽  
Production Wells ◽  
The Uk

AbstractThe Maureen Oilfield is located on a fault-bounded terrace in Block 16/29a of the UK Sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in late 1972 by the 16/29-1 well, and was confirmed by three further appraisal wells. The reservoir consists of submarine fan sandstones of the Palaeocene Maureen Formation, deposited by sediment gravity flows sourced from the East Shetland Platform. The Palaeocene sandstones, ranging from 140 to 400 ft in thickness, have good reservoir properties, with porosities ranging from 18-25% and permeabilities ranging from 30-3000 md. Hydrocarbons are trapped in a simple domal anticline, elongated NW-SE, which was formed at the Palaeocene level by Eocene/Oligocene-aged movement of underlying Permian salt. The reservoir sequence is sealed by Lista Formation claystones. Geochemical analysis suggests Upper Jurassic Kimmeridge Clay shales have been the source of Maureen hydrocarbons. Estimated recoverable reserves are 210 MMBBL. Twelve production wells have been drilled on the Maureen Field. A further seven water injection wells have been drilled to maintain reservoir pressure.

scholarly journals Environmental conditions and diffusion-limited microbial transfer drive specific microbial communities detected at different sections in oil-production reservoir with water-flooding

2020 ◽  
Author(s):  
Peike Gao ◽  
Huimei Tian ◽  
Guoqiang Li ◽  
Feng Zhao ◽  
Wenjie Xia ◽  
...  
Keyword(s):  
Microbial Communities ◽  
Water Injection ◽  
Oil Production ◽  
Environmental Variation ◽  
Water Flooding ◽  
Petroleum Reservoir ◽  
Diffusion Limited ◽  
Production Wells ◽  
And Diffusion ◽  
Production Facilities

ABSTRACTThis study investigated the distribution of microbial communities in the oilfield production facilities of a water-flooding petroleum reservoir and the roles of environmental variation, microorganisms in injected water, and diffusion-limited microbial transfer in structuring the microbial communities. Similar bacterial communities were observed in surface water-injection facilities dominated by aerobic or facultative anaerobic Betaproteobacteria, Alphaproteobacteria, and Flavobacteria. Distinct bacterial communities were observed in downhole of the water-injection wells dominated by Clostridia, Deltaproteobacteria, Anaerolineae, and Synergistia, and in the oil-production wells dominated by Gammaproteobacteria, Betaproteobacteria, and Epsilonproteobacteria. Methanosaeta, Methanobacterium, and Methanolinea were dominant archaeal taxa in the water-injection facilities, while the oil-production wells were predominated by Methanosaeta, Methanomethylovorans, and Methanocalculus. Energy, nucleotide, translation, and glycan biosynthesis metabolisms were more active in the downhole of the water-injection wells, while bacterial chemotaxis, biofilm formation, two-component system, and xenobiotic biodegradation was associated with the oil-production wells. The number of shared OTUs and its positive correlation with formation permeability revealed differential diffusion-limited microbial transfer in oil-production facilities. The overall results indicate that environmental variation and microorganisms in injected water are the determinants that structure microbial communities in water-injection facilities, and the determinants in oil-bearing strata are environmental variation and diffusion-limited microbial transfer.IMPORTANCEWater-flooding continually inoculates petroleum reservoirs with exogenous microorganisms, nutrients, and oxygen. However, how this process influences the subsurface microbial community of the whole production process remains unclear. In this study, we investigated the spatial distribution of microbial communities in the oilfield production facilities of a water-flooding petroleum reservoir, and comprehensively illustrate the roles of environmental variation, microorganisms in injected water, and diffusion-limited microbial transfer in structuring the microbial communities. The results advance fundamental understanding on petroleum reservoir ecosystems that subjected to anthropogenic perturbations during oil production processes.

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.

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

2019 ◽  
Author(s):  
Tomislav Malvić ◽  
Josip Ivšinović ◽  
Josipa Velić ◽  
Jasenka Sremac ◽  
Uroš Barudžija
Keyword(s):  
Water Injection ◽  
Water Reservoir ◽  
Inverse Distance Weighting ◽  
Hydrocarbon Reservoirs ◽  
Water Flooding ◽  
Injection Wells ◽  
Weighting Method ◽  
Recovery Method ◽  
Distance Weighting ◽  
Inverse Distance

Here is analysed the process of water re-injection in the two hydrocarbon reservoirs/fields in the Upper Miocene sandstone reservoirs, located in the western part of the Sava Depression (Croatia). Namely, those are the "A" field with "L" reservoir and the "B" field with "K" reservoir. Both currently produce hydrocarbons using a secondary recovery method, i.e. water injection (in fact re-injection of the field waters). Three regional reservoir variables had been analysed, namely porosity, permeability and injected water volumes. The number of data was small in all three cases. For porosity: reservoir “L” included 25 data, reservoir “K” 19 data; for permeability: reservoir “L” 10 data, reservoir “K” 18 data; for injected volumes of water: reservoir “L” 10 data; reservoir “K” 3 data. It defined selection of mapping algorithms mostly designed for small datasets (less than 20 points), i.e. Inverse Distance Weighting, Nearest and Natural Neighbourhood. Additionally, the Ordinary Kriging was used, but only with jack-knifed variograms, producing many “artificial points”. Results are extensively tested, using cross-validation and shape recognitions, and the Inverse Distance Weighting method is described as the most appropriate approach for mapping permeability and injected volumes in both reservoirs (“K” and “L”). The Kriging could be slightly outlined as the best approach for porosity. Obtained maps made possible application of the modified geological probability calculation as tools for prediction of successfulness of future injection (probability of 0.56). Consequently, results made possible to plan future injection more efficiently, with smaller injected volumes and same of higher hydrocarbon recovery. That could prevent useless injection, decrease number of injection wells, and save energy and funds invested in such processes.

Sign in / Sign up

Export Citation Format

Share Document