Paradigm Shift from Cemented Completions to Multi-Stage Completion Strategy for Managing Tight Gas Development Challenges

2021 ◽  
Author(s):  
Mohamed Abdel-Basset ◽  
Yousef Al-Otaibi ◽  
Abdulla Al-Saeed ◽  
Taha Blushi ◽  
Erkan Fidan ◽  
...  
Keyword(s):  
Paradigm Shift ◽  
Operation Time ◽  
Carbonate Reservoir ◽  
Tight Gas ◽  
Natural Fractures ◽  
Well Productivity ◽  
Heterogeneous Reservoirs ◽  
Well Completion ◽  
Multi Stage ◽  
Production Target

Abstract The development of North Kuwait Jurassic gas assets has strategic importance for Kuwait's production strategy as the only non-associated gas-producing field in Kuwait. This paper demonstrates the benefits, challenges and lessons learned of the recent paradigm shift in Jurassic tight gas wells’ completion strategy from cemented liner to multi-stage completion. Successful expansion of Multi-Stage Completion (MSC) technology is achieved at the field level led by the integrated team efforts in 2020/21, despite challenging constraints of COVID-19. MSC's help to enhance overall well production potential, overcome reservoir and intervention operation challenges, and allow early production delivery, which is a key factor to achieve a strategic asset production target of 70-80% by 2024/25. Many technical and logistic challenges were experienced during first installations of which the relevant learnings will be shared in this paper. The Jurassic gas asset produces mainly from deep high pressure and temperature, conventional and unconventional tight carbonate reservoirs. The recovery from such complex heterogeneous reservoirs is extremely challenging if conventional development strategies are applied. Therefore, a dedicated full development plan applying integrated upstream and downstream technologies is important to achieve the strategic production target. Due to the excessive Jurassic carbonate reservoir tightness, permeability contrast and dual permeability effect (matrix and natural fractures), well productivity potential significantly depends on the effectiveness of subsequent stimulation treatments of such complex heterogeneous reservoirs to improve well productivity and potentially connect with natural fractures. Selecting proper well completion design is critical to overcome such reservoir challenges and ensure effective acid stimulation treatments for the mix of conventional and unconventional formations that need convenient diversion mechanism during stimulation to enhance the productivity of each individual reservoir flow unit and enable selective future flexibility of re-stimulation and reservoir management. The asset team has recently applied a step change in completion strategy to open hole multi-stage ball drop completions using state of the art MSC technologies including closeable frac sleeves, full 3.5-in monobore ID post frac sleeves milling and debris sub enclosure to protect the MSC string during casing tie-back operations. This is to overcome reservoir complexity, eliminate wellbore cleaning and decrease the challenges and risks that accompany multiple perforation intervention operations. As well as, eliminate cement quality risks and uncertainties, improve overall cost, and fast track well delivery to production to meet asset production targets by significantly reducing operation time from approximately one month for plug and perf techniques to less than one week when using continuous and less subsurface intervention operations. Recently, a total of 13 new MSC installations and subsequent multi-stage stimulations were achieved in seven months, fromQ3-2020 to Q1-2021, with positive overall production results, significant improvement of intervention operation efficiency and faster well delivery to production. This paper will describe the details of progress to date, and the plan forward for optimization and new technology trials to further improve well performance.

Evaluation of damage mechanisms and skin factor in tight gas reservoirs

2011 ◽  
Vol 51 (1) ◽  
pp. 639 ◽  
Author(s):  
Hassan Bahrami ◽  
Reza Rezaee ◽  
Delair Nazhat ◽  
Jakov Ostojic
Keyword(s):  
Significant Influence ◽  
Permeability Reduction ◽  
Tight Gas ◽  
Natural Fractures ◽  
Gas Reservoirs ◽  
Damage Mechanisms ◽  
Well Productivity ◽  
Tight Gas Reservoirs ◽  
Skin Factor ◽  
Water Blocking

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques. The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include: mechanical damage to formation rock; plugging of natural fractures by mud solid particle invasion; relative permeability reduction around wellbore as a result of filtrate invasion; liquid leak-off into the formation during fracturing operations; water blocking; skin due to wellbore breakouts; and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occurs through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures. This study represents an evaluation of different damage mechanisms in tight gas formations, and examines the factors that can have significant influence on total skin factor and well productivity. Reservoir simulation was carried out based on a typical West Australian tight gas reservoir to understand how well productivity is affected by each of the damage mechanisms, such as natural fracture plugging, mud filtrate invasion, water blocking and perforation. Furthermore, some damage prevention and productivity improvement techniques are proposed, which can help improve well productivity in tight gas reservoirs.

Natural fractures in tight gas sandstones: a case study of the Upper Triassic Xujiahe Formation in Xinchang gas field, Western Sichuan Basin, China

2021 ◽  
pp. 1-18
Author(s):  
Yunzhao Zhang ◽  
Lianbo Zeng ◽  
Wenya Lyu ◽  
Dongsheng Sun ◽  
Shuangquan Chen ◽  
...  
Keyword(s):  
Production Capacity ◽  
Gas Production ◽  
Upper Triassic ◽  
Tight Gas ◽  
Natural Fractures ◽  
Carbon And Oxygen Isotopes ◽  
Gas Field ◽  
Xujiahe Formation ◽  
Western Sichuan ◽  
Tight Gas Reservoir

Abstract The Upper Triassic Xujiahe Formation is a typical tight gas reservoir in which natural fractures determine the migration, accumulation and production capacity of tight gas. In this study, we focused on the influences of natural fractures on the tight gas migration and production. We clarified characteristics and attributes (i.e. dips, apertures, filling degree and cross-cutting relationships) of the fractures based on image logging interpretations and core descriptions. Previous studies of electron spin resonance, carbon and oxygen isotopes, homogenization temperature of fluid inclusions analysis and basin simulation were considered. This study also analysed the fracture sequences, source of fracture fillings, diagenetic sequences and tight gas enrichment stages. We obtained insight into the relationship between fracture evolution and hydrocarbon charging, particularly the effect of the apertures and intensity of natural fractures on tight gas production. We reveal that the bedding fractures are short horizontal migration channels of tight gas. The tectonic fractures with middle, high and nearly vertical angles are beneficial to tight gas vertical migration. The apertures of fractures are controlled by the direction of maximum principal stress and fracture angle. The initial gas production of the vertical wells presents a positive correlation with the fracture abundance, and the intensity and aperture of fractures are the fundamental factors that determine the tight gas production. With these findings, this study is expected to guide the future exploration and development of tight gas with similar geological backgrounds.

scholarly journals Aggressors and resilient youths in Medellin, Colombia: the need for a paradigm shift in order to overcome violence

2013 ◽  
Vol 29 (11) ◽  
pp. 2208-2216 ◽  
Author(s):  
Luis F. Duque ◽  
Nilton E. Montoya ◽  
Alexandra Restrepo
Keyword(s):  
Public Policy ◽  
Cross Section ◽  
Metropolitan Area ◽  
Paradigm Shift ◽  
Prevention And Control ◽  
High Ratio ◽  
Multi Stage ◽  
Sexually Risky ◽  
And Control ◽  
Resilient Behavior

The objective of this study was to estimate the ratio of resilient youth and compare this to youth with aggressive behavior, and to youth who also exhibit sexually risky behavior and drug use. A cross-section study of a representative sample of people between aged between 12 and 60 who are residents of Medellin, Colombia, and its metropolitan area (N = 4,654) was employed using probabilistic multi-stage sampling. Youth between 14 and 26 years old were selected for the present analysis (n = 1,780). The proportion of resilient youth is 22.9%, of aggressors is 11.3%, and that of youth with other risky conduct is 65.8%. The high ratio of resilient youth calls for a reorientation of public policy toward prevention and control of violence, prioritizing the promotion of resilient behavior instead of continuing with tertiary prevention actions.

Redevelopment of a Matured Multilayered Carbonate Offshore Field Through High Technology Horizontal and Multilateral Wells

2007 ◽  
Vol 10 (05) ◽  
pp. 453-457 ◽  
Author(s):  
Rajesh Kumar ◽  
S. Ramanan ◽  
J.L. Narasimham
Keyword(s):  
New Technologies ◽  
High Technology ◽  
Horizontal Wells ◽  
Development Stage ◽  
Scientific Data ◽  
Carbonate Reservoir ◽  
Western India ◽  
Drilling Fluids ◽  
Well Productivity ◽  
Offshore Field

Summary Oil productivity from Mumbai High field, an offshore multilayered carbonate reservoir, increased significantly through the implementation of a major redevelopment program. Geoscientific information available from approximately 700 exploratory and develop- ment wells drilled in the field during nearly 25 years was incorporated during geological and reservoir simulation modeling of the field. High-technology drilling (viz. horizontal/multilaterals for the new development wells) was adopted on field scale to effectively address typical complexity of the layered carbonate reservoirs. Since the commencement of the project in 2000, approximately 140 new wells were drilled, mostly with horizontal and multilateral drainholes. Besides these, more than 70 suboptimal producers were also converted as horizontal sidetracks under brownfield development. The horizontal sidetracks were drilled as long-drift sidetrack (LDST), extended-reach drilling (ERD), LDST-ERD, short-drift sidetrack (SDST), and medium-radius drainhole (MRDH) types of wells through the application of innovative and emerging drilling technologies with nondamaging drilling fluids, whipstocks to kick off sidetrack wells, rotary-steering systems, and expandable tubulars to complete horizontal sidetracks in lower layers. With the implementation of this project, the declining trend was fully arrested and a significant upward trend in production has been established. Introduction The field redevelopment process requires the intergration of reservoir-development strategies, facility options, and drilling and production philosophies to maximize oil and gas recovery from a matured field. A significant number of case studies are available on mature field revitalization using a multidisciplinary team concept, exhaustive geo-scientific data analysis, and new drilling technologies (Chedid and Colmenares 2002; Clark et al. 2000; Dollens et al. 1999; Kinchen et al. 2001). Advancements in drilling and completion technology have enabled construction of horizontal wells with longer wellbores, more-complex well geometry, and sophisticated completion designs. Horizontal wells provide an effective method to produce bypassed oil from matured fields. In the early 1980s, this technology was in the development stage and was used in limited applications. By the 1990s, the technology had matured, and its acceptance in the industry had increased significantly. Performance of horizontal/multilateral wells, risk assessment of horizontal-well productivity and comparison of horizontal- and vertical-well performance in different fields is available in literature (Babu and Aziz 1989; Brekke and Thompson 1996; Economides et al. 1989; Joshi 1987; Joshi and Ding 1995; Mukherjee and Economides 1991; Norris et al. 1991; Vij et al. 1998). A significant number of horizontal/multilateral development wells were drilled as a part of redevelopment of Mumbai High, a matured multilayered carbonate offshore field in Western India. The details of new technologies applied and performance of these new high-technology wells are presented in this paper. Besides comparison of well productivity of horizontal and conventional sidetrack wells, this paper presents some technical issues faced.

scholarly journals Development of machine learning predictive models for history matching tight gas carbonate reservoir production profiles

2018 ◽  
Vol 15 (5) ◽  
pp. 2235-2251 ◽  
Author(s):  
Eric Thompson Brantson ◽  
Binshan Ju ◽  
Busayo Oreoluwa Omisore ◽  
Dan Wu ◽  
Aphu Elvis Selase ◽  
...  
Keyword(s):  
Machine Learning ◽  
Predictive Models ◽  
History Matching ◽  
Carbonate Reservoir ◽  
Tight Gas

Extended-Time Conductivity Testing of Proppants Used for Multi-Stage Horizontal Completions

2022 ◽  
Author(s):  
C. Mark Pearson ◽  
Christopher A. Green ◽  
Mark McGill ◽  
David Milton-Tayler
Keyword(s):  
American Petroleum Institute ◽  
Late Time ◽  
Extended Time ◽  
Economic Optimization ◽  
Time Data ◽  
Fracture Conductivity ◽  
White Sand ◽  
Productive Life ◽  
Well Completion ◽  
Multi Stage

Abstract The American Petroleum Institute Recommended Practice 19-D (2018) is the current industry standard for conductivity testing of proppants used in hydraulic fracturing. Similar to previous standards from both the API and ISO, it continues the practice of measuring a "reference" long-term conductivity after 50-hours of time at a given stress. The fracture design engineer is then left to estimate a damage factor to apply over the life of the well completion based on correlations or experience. This study takes four standard proppants used for multi-stage horizontal well completions in North America and presents test data over 250-days of "extended-time" at 7,500 psi of effective stress. The API RP 19-D procedure was followed for all testing, but extended for 250-days duration for the four proppant types: 40/70 mesh mono-crystalline "White" sand, 40/70 mesh multi-crystalline "Brown" sand, 100 mesh "Brown" sand, and 40/70 mesh Light Weight Ceramic (LWC). The 7,500 psi stress condition was chosen to replicate initial stress conditions for a 10,000 feet deep well with a 0.75 psi/ft fracture gradient - typical of unconventional resource plays such as the Bakken formation of North Dakota or the Delaware Basin in west Texas. Results presented provide a measure of the amount of damage occurring in the proppant pack due to time at stress. To the authors’ knowledge, there has never been any extended-time conductivity data published for multiple proppant types over the timeframe completed in this study - despite the obvious need for this understanding to optimize the stimulation design over the full life of the well. Results for the four proppant types are presented as conductivity curves as a function of time for the 250-days of testing. Pack degradation is shown to follow a semi-log decline. Late time continued degradation for all materials is extrapolated over the life of a typical well (40 years), and compared to extended-time particle size distribution and crush data to explain the results observed. Extended-time data such as this 250-day study have never been published on proppants such as these despite the fact that fracture conductivity has a major impact on the productive life of a well and the ultimate recovery of hydrocarbons from the formation. The data presented should be of great interest to any engineer involved with completion designs, or reservoir engineers assessing the productive life and ultimate recovery in the formation since economic optimization is primarily driven by the interplay of fracture length/area with extended-time in-situ fracture conductivity.

Advanced Well Completion Strategies to Improve Gas Production Deliverability in Marginal Tight Gas Reservoirs from an Onshore Abu Dhabi Gas Field

2021 ◽  
Author(s):  
Hajar Ali Abdulla Al Shehhi ◽  
Bondan Bernadi ◽  
Alia Belal Zuwaid Belal Al Shamsi ◽  
Shamma Jasem Al Hammadi ◽  
Fatima Omar Alawadhi ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Wells ◽  
Gas Production ◽  
Abu Dhabi ◽  
Tight Gas ◽  
Production Rates ◽  
Well Productivity ◽  
Gas Saturation ◽  
Well Design ◽  
The Impact

Abstract Reservoir X is a marginal tight gas condensate reservoir located in Abu Dhabi with permeability of less than 0.05 mD. The field was conventionally developed with a few single horizontal wells, though sharp production decline was observed due to rapid pressure depletion. This study investigates the impact of converting the existing single horizontal wells into single long horizontal, dual laterals, triple laterals, fishbone design and hydraulic fracturing in improving well productivity. The existing wells design modifications were planned using a near reservoir simulator. The study evaluated the impact of length, trajectory, number of laterals and perforation intervals. For Single, dual, and triple lateral wells, additional simulation study with hydraulic fracturing was carried out. To evaluate and obtain effective comparisons, sector models with LGR was built to improve the simulation accuracy in areas near the wellbore. The study conducted a detailed investigation into the impact of various well designs on the well productivity. It was observed that maximizing the reservoir contact and targeting areas with high gas saturation led to significant increase in the well productivity. The simulation results revealed that longer laterals led to higher gas production rates. Dual lateral wells showed improved productivity when compared to single lateral wells. This incremental gain in the production was attributed to increased contact with the reservoir. The triple lateral well design yielded higher productivity compared to single and dual lateral wells. Hydraulic fracturing for single, dual, and triple lateral wells showed significant improvement in the gas production rates and reduced condensate banking near the wellbore. A detailed investigation into the fishbone design was carried out, this involved running sensitivity runs by varying the number of branches. Fishbone design showed considerable increment in production when compared to other well designs This paper demonstrates that increasing the reservoir contact and targeting specific areas of the reservoir with high gas saturation can lead to significant increase in the well productivity. The study also reveals that having longer and multiple laterals in the well leads to higher production rates. Hydraulic fracturing led to higher production gains. Fishbone well design with its multiple branches showed the most production again when compared to other well designs.

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