scholarly journals Law and countermeasures for the casing damage of oil production wells and water injection wells in Tarim Oilfield

2011 ◽  
Vol 38 (3) ◽  
pp. 352-361 ◽  
Author(s):  
Wang Tao ◽  
Yang Shenglai ◽  
Zhu Weihong ◽  
Bian Wanjiang ◽  
Liu Min ◽  
...  
Keyword(s):  
Water Injection ◽  
Oil Production ◽  
Injection Wells ◽  
Casing Damage ◽  
Production Wells

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

Predicting and optimising the mature Windalia waterflood based on a capacitance-resistance model (CRM)

2012 ◽  
Vol 52 (2) ◽  
pp. 656
Author(s):  
Wee Yong Gan ◽  
Lina Hartanto ◽  
Andrew Haynes ◽  
Morteza Sayarpour
Keyword(s):  
Water Injection ◽  
Oil Production ◽  
Operating Conditions ◽  
Significant Heterogeneity ◽  
Well Performance ◽  
Fractional Flow ◽  
Injection Wells ◽  
Resistance Model ◽  
Production Wells ◽  
The Impact

Waterflood development drilling of the Windalia reservoir on Barrow Island at 40-acre spacing started in 1968, using five-spot and nine-spot inverted drive flood patterns. There was a general conversion to line drive in mid-1970 with various infill and realignment projects. The field comprises more than 220 active injectors and 400 producers. The reservoir is geologically complex, with low permeability and significant heterogeneity. Historically, empirical techniques and fractional flow models were used for forecasting, but these approaches have many inherent limitations; for example, they do not provide individual well performance and they are not sensitive to changes in operating conditions. More recently, a capacitance-resistance model (CRM) that uses historical injection and production data has been used to establish long-term behaviours between water injection and oil production wells, including inter-well connectivity, delay time constants and productivity indices. The evaluation of these behaviours allows direct quantification of waterflood efficiency at well-to-well level and improves identification of opportunities for changing injection patterns and prioritisation of operations and well workovers. Optimisation and forecasting of the Windalia waterflood is performed by maximising cumulative oil production by reallocating the available field wide injection water and evaluating individual injection wells target rates. Numerous optimisation scenarios were built into the models to account for the impact of changing operating conditions such as water availability and aging of wells and processing facilities. CRM is robust and is appropriate for simultaneous optimisation of well rates in a field where water injection and oil production wells are shut-in frequently. The PowerPoint presentation is not available to APPEA.

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.

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.

Revisiting the Eland Field Lodgepole Mound Complex (Stark County, North Dakota) Twenty Years after its Discovery

2016 ◽  
Vol 53 (1) ◽  
pp. 29-70 ◽  
Author(s):  
Mark Longman ◽  
Stephen Cumella
Keyword(s):  
North Dakota ◽  
Black Shale ◽  
Water Injection ◽  
Oil Production ◽  
Fracture Network ◽  
Williston Basin ◽  
Injection Wells ◽  
Reservoir Rocks ◽  
Type Area ◽  
Central Montana

Eland Field, the most prolific Lower Mississippian Lodgepole mound complex found to date in the Williston Basin, covers an area of about 6 mi2 and has produced more than 29 MMBO from 16 wells in the 20 years since the field was discovered. Three of the field’s updip wells have each produced more than 4 MMBO from mounds more than 250 ft thick although generally only the top 20 to 30 ft of the mound is perforated. The lower Lodgepole reservoir rocks are commonly called Waulsortian mounds, but they are Waulsortian in age only and not the micrite-rich mudmounds found in the type area of Waulsort, Belgium. Instead of being mudmounds, they are composed mainly of marine-cemented microbial boundstones and skeletal grainstones with local stromatactis structures. The edges of the mounds dip as steeply as 40 to 60 degrees. Such steep dips would be impossible in a typical micrite-rich Waulsortian mound. In addition to the abundant microbial and marine cementation that lithified the Eland Field mound complex penecontemporaneously, organisms such as stalked crinoids, fenestrate bryozoans, and articulated brachiopods and ostracods thrived on the hard substrate provided by the mounds. However, these organisms were themselves incapable of forming a true reef framework. Unusual inward dip of the Upper Bakken black shale and significant thickening of the “Extra Bakken Shale” from zero up to about 40 ft immediately beneath the oil-producing lower Lodgepole mounds both support the idea that something structurally significant such as salt dissolution helped localize mound development. We conclude that dissolution of the Lower Devonian Prairie salt created a fracture network during and immediately after deposition of the upper Bakken black shale that allowed compaction-water expulsion-vents and/or warm springs to initiate formation of carbonate “towers” that localized formation of the Lodgepole mounds. The discovery well for Eland Field, the Knopik #1-11 (NW NW Sec. 11, T139N, R97W), was completed in January 1995 for 2707 BOPD and 1550 MCFGPD with no water. The field was developed over the next few years with up to 16 producing wells and 7 water injection wells. Waterflooding of Eland Field began in 1997 and climbed to over 500,000 barrels per month in just two months. Through September 2015, more than 95 MMBW had been injected into the field, but it has produced over 29.6 MMBO, doubling the 1996 estimated ultimate recovery of 12 to 15 MMBO. The field continues to produce with about a 5.5% oil cut. In terms of total cumulative oil production in the U.S. portion of the Williston Basin, Eland Field contains 3 of the top 10 wells, and other nearby Lodgepole producing fields contain 4 additional top 10 wells. This excellent oil production leads to the question: Is it possible that the only productive Lodgepole mound reservoirs in the Williston Basin, eight of which have been discovered to date (with all but one discovered in the mid-1990s) are limited to a small atoll-like area about 7 miles in diameter in northern Stark County, North Dakota? Certainly the presence of similar Lodgepole mounds in outcrops in central Montana (e.g., Bridger Range and Big Snowy and Little Belt mountains) and in the subsurface of the western Williston Basin suggests that other Lodgepole mound-type reservoirs could occur across much of the basin. The most promising areas in which to search for other Lodgepole mound reservoirs will be those where the Upper Bakken black shale is well developed and thermally mature because it is the source for the oil in the Lodgepole reservoirs in the Eland Field area.

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.

Slowing Production Decline and Extending the Economic Life of an Oil Field: New MEOR Technology

2002 ◽  
Vol 5 (01) ◽  
pp. 33-41 ◽  
Author(s):  
L.R. Brown ◽  
A.A. Vadie ◽  
J.O. Stephens
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Enhanced Recovery ◽  
Water Injection ◽  
Oil Production ◽  
Oil Field ◽  
Economic Life ◽  
Oil Reservoir ◽  
Injection Wells ◽  
Black Warrior Basin

Summary This project demonstrated the effectiveness of a microbial permeability profile modification (MPPM) technology for enhancing oil recovery by adding nitrogenous and phosphorus-containing nutrients to the injection water of a conventional waterflooding operation. The MPPM technology extended the economic life of the field by 60 to 137 months, with an expected recovery of 63 600 to 95 400 m3 (400,000 to 600,000 bbl) of additional oil. Chemical changes in the composition of the produced fluids proved the presence of oil from unswept areas of the reservoir. Proof of microbial involvement was shown by increased numbers of microbes in cores of wells drilled within the field 22 months after nutrient injection began. Introduction The target for enhanced oil recovery processes is the tremendous quantity of unrecoverable oil in known deposits. Roughly two thirds [approximately 55.6×109 m3 (350 billion bbl)] of all of the oil discovered in the U.S. is economically unrecoverable with current technology. Because the microbial enhanced oil recovery (MEOR) technology in this report differs in several ways from other MEOR technologies, it is important that these differences be delineated clearly. In the first place, the present project is designed to enhance oil recovery from an entire oil reservoir, rather than treat single wells. Even more important is the fact that this technology relies on the action of the in-situ microflora, not microorganisms injected into the reservoir. It is important to note that MPPM technology does not interfere with the normal waterflood operation and is environmentally friendly in that neither microorganisms nor hazardous chemicals are introduced into the environment. Description of the Oil Reservoir. The North Blowhorn Creek Oil Unit (NBCU) is located in Lamar County, Alabama, approximately 75 miles west of Birmingham. This field is in what is known geologically as the Black Warrior basin. The producing formation is the Carter sandstone of Mississippian Age at a depth of approximately 700 m (2,300 ft). The Carter reservoir is a northwest/ southeast trending deltaic sand body, approximately 5 km (3 miles) long and 1 to 1.7 km (1/2 to 1 mile) wide. Sand thickness varies from only 1 m up to approximately 12 m (40 ft). The sand is relatively clean (greater than 90% quartz), with no swelling clays. The field was discovered in 1979 and initially developed on 80-acre spacing. Waterflooding of the reservoir began in 1983. The initial oil in place in the reservoir was approximately 2.54×106 m3 (16 million bbl), of which 874 430 m3 (5.5 million bbl) had been recovered by the end of 1995. To date, North Blowhorn Creek is the largest oil field discovered in the Black Warrior basin. Oil production peaked at almost 475 m3/d (3,000 BOPD) in 1985 and has since declined steadily. Currently, there are 20 injection wells and 32 producing wells. Oil production at the outset of the field demonstration was approximately 46 m3/d oil (290 BOPD), 1700 m3/d gas (60 MCFD), and 493 m3/d water (3,100 BWPD), with a water-injection rate of approximately 660 m3/d (4,150 BWPD). Projections at the beginning of the project were that approximately 1.59×106 m3 oil (10 million bbl of oil) would be left unrecovered if some new method of enhanced recovery were not effective. Prefield Trial Studies The concepts of the technology described in this paper had been proven to be effective in laboratory coreflood experiments.1,2 However, it seemed advisable to conduct coreflood experiments with cores from the reservoir being used in the field demonstration. Toward this end, two wells were drilled, and cores were obtained from one for the laboratory coreflood experiments to determine the schedule and amounts of nutrients to be employed in the field trial.3

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