Field Optimization Via Data Approach: A Case Study of Data Mining for Tight Gas Flowback Evaluations

2021 ◽  
Author(s):  
Yuan Liu ◽  
Bin Li ◽  
Hongjie Zhang ◽  
Fan Yang ◽  
Guan Wang ◽  
...  
Keyword(s):  
Data Mining ◽  
Production Performance ◽  
Reservoir Quality ◽  
Tight Gas ◽  
Well Performance ◽  
Gas Field ◽  
Field Development ◽  
Field Level ◽  
Depth Analysis ◽  
The Impact

Abstract The economics of tight gas fields highly depend on the consistency between expected production and the actual well performance. A mismatch between the reservoir quality and the well production often leads to a review of the individual well. However, such mismatch may vary from case to case, and it is hard to perform a field-level analysis based on individual well reviews. We introduce a new method based on data mining to assist the field-level diagnosis. LX gas field is located the in eastern Ordos basin. Compared to the main gas field in the center of the basin, LX field is less predictable in well performance. This predictability issue hinders field development in LX field because the field economics are substantially jeopardized by the inconsistency between the reservoir quality and the production performance. The traditional workflow to understand this issue at the field level is to review the details of a large number of individual wells in the area. This is typically an intense task, and too much detail from multiple disciplines may hide the true pattern of the field behavior. To resolve this issue, we applied data mining in our field development diagnosis workflow. Our new workflow in LX area started with the existing field datasheet, including logging summaries, completion treatment reports, and flowback testing datasheets. With the data extracted from these different sources, we visualized the consolidated information in various plots and graphs based on regression analysis, which revealed the relation between flowback ratio and the production, the flowback rate consistency from the different service suppliers, and the impact of water productions. The data mining approach helped to generate new understandings in LX gas field. With the in-depth analysis of the flowback data together with reservoir properties and operation parameters, the key problems in the field were identified for further development optimization, and the field economics can be significantly improved. The diagnosis method can be easily adapted and applied to any field with similar problems, and data mining can be useful for almost all large-scale field development optimizations.

From Technical Evolution to Production Performance: A Technical Review of 700 Wells Over 8 Years in the South Sulige Tight Gas Field

2022 ◽  
Author(s):  
Dong Wang ◽  
Yifan Dong ◽  
Shengfang Yang ◽  
Joel Rignol ◽  
Qiang Wang ◽  
...  
Keyword(s):  
Joint Venture ◽  
Ordos Basin ◽  
Production Performance ◽  
Reservoir Quality ◽  
Tight Gas ◽  
Well Performance ◽  
Gas Field ◽  
Technical Review ◽  
The Ordos Basin ◽  
High Level

Abstract Unlike many unconventional resources that demonstrate a high level of heterogeneity, conventional tight gas formations often perform consistently according to reservoir quality and the applied completion technology. Technical review over a long period may reveal the proper correlation between reservoir quality, completion technology, and well performance. For many parts of the world where conventional tight gas resources still dominate, the learnings from a review can be adapted to improve the performance of reservoirs with similar features. South Sulige Operating Company (SSOC), a joint venture between PetroChina and Total, has been operating in the Ordos basin for tight gas since 2011. The reservoir is known to have low porosity, low permeability, and low reservoir pressure, and requires multistage completion and fracturing to achieve economic production. Over the last 8 years, there has been a clear technical evolution in South Sulige field, as a better understanding of the reservoir, improvement of the completion deployment, optimized fracturing design, and upgraded flowback strategy have led to the continuous improvement of results in this field. Pad drilling of deviated boreholes, multistage completions with sliding sleeve systems, hybrid gel-fracturing, and immediate flowback practices, gradually proved to be the most effective way to deliver the reservoir's potential. Using the absolute open-flow (AOF) during testing phase for comparative assessment from South Sulige field, we can see that in 2012 this number was 126 thousand std m3/d in 2012, and by 2018 this number had increased to 304 thousand std m3/d, representing a 143% incremental increase. Thus, technical evolution has been proved to bring production improvement over time. Currently, South Sulige field not only outperforms offset blocks but also remains the top performer among the fields in the Ordos basin. The drilling and completion practices from SSOC may be well suited to similar reservoirs and fields in the future.

Prediction of Reservoir Quality & Deliverability of the Tight Barik Formation in Khazzan Field, Oman

2021 ◽  
Author(s):  
Khalil Ali Al Rashdi ◽  
Martin Wells ◽  
Nigel Clark
Keyword(s):  
Gamma Ray ◽  
Analytical Techniques ◽  
Reservoir Quality ◽  
Petrographic Analysis ◽  
Well Performance ◽  
Burial History ◽  
Gas Field ◽  
Field Development ◽  
Well Production ◽  
Porosity And Permeability

Abstract The giant Khazzan gas field, located in onshore Oman, has been under development since 2013 and in production since 2017. The field is currently producing 1 billion cubic feet of gas per day from the Cambro-Ordovician Barik Formation. The 80-metre-thick paralic reservoir is 4.5 kilometers deep and has undergone complex stages of diagenesis, hydrocarbon charge and structural regime changes. Reservoir quality (RQ) is typically classed as tight (average porosity 6 porosity unit, average permeability 1 Milidarcy) but locally exceeds expectations given the burial history reaching up to 12 pu and 100 Milidarcy. This RQ variability and complexity makes reservoir deliverability (RD) a key uncertainty impacting the field development scheme and ultimately the projected economics. This study aims to create and test hypotheses of RQ and RD controls to reduce uncertainty in production and increase reservoir development efficiency. In order to better understand the key controls on reservoir quality, an extensive set of core, petrophysical log analysis and production data were integrated with field-wide seismic and outcrop data to update the Barik stratigraphic, structural and depositional frameworks. Extensive analytical techniques, including reservoir quality modelling, petrographic analysis, X-ray diffraction, mercury injection capillary pressure and minipermeameter data were also integrated. Quartz cementation and compaction are the principal degrading controls on reservoir quality. The controls on quartz cementation are complex and variably inter-related, although in general it is ductile content, proximity to mudstone and feldspar content that are the best predictors of porosity and permeability when convolved. Minipermeameter data confirms that distance to mudstone, or sandstone thickness, is an important control on reservoir quality. Using normalized gamma ray log data, total and mean individual sandstone thickness were calculated for every Barik well in Khazzan and compared to well dynamic behavior which demonstrated a positive correlation. Areas with high mean individual sandstone thickness and total sandstone thickness frequently equate with relatively high IP30s (average well production at 1100 psi well head pressure for 30 days). In contrast, areas with high total sandstone thickness, but low mean individual sandstone thickness may only have moderate IP30s as those sandstones may be more quartz cemented. Reservoir deliverability risk maps based on total and mean individual sandstone thickness and IP30 were constructed. These maps give insight into regions of poor and good gas deliverability and have identified areas that may be untested or undeveloped that may have potential upside. The resultant reservoir deliverability understanding of the Barik formation is consistent with depositional environment, diagenetic understanding and well performance. It is a good example of integrating diverse static and dynamic data to improve reservoir understanding and has direct business impact.

Utilizing Pseudo Well Connections to Simulate Multi-Stage Hydraulic Fracturing - Example Based On the Study of a Tight Gas Asset

2021 ◽  
Author(s):  
Aamir Lokhandwala ◽  
Vaibhav Joshi ◽  
Ankit Dutt
Keyword(s):  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Flow Simulation ◽  
Oil And Gas Industry ◽  
Development Plan ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Field ◽  
Field Development ◽  
Fracture Modeling

Abstract Hydraulic fracturing is a widespread well stimulation treatment in the oil and gas industry. It is particularly prevalent in shale gas fields, where virtually all production can be attributed to the practice of fracturing. It is also used in the context of tight oil and gas reservoirs, for example in deep-water scenarios where the cost of drilling and completion is very high; well productivity, which is dictated by hydraulic fractures, is vital. The correct modeling in reservoir simulation can be critical in such settings because hydraulic fracturing can dramatically change the flow dynamics of a reservoir. What presents a challenge in flow simulation due to hydraulic fractures is that they introduce effects that operate on a different length and time scale than the usual dynamics of a reservoir. Capturing these effects and utilizing them to advantage can be critical for any operator in context of a field development plan for any unconventional or tight field. This paper focuses on a study that was undertaken to compare different methods of simulating hydraulic fractures to formulate a field development plan for a tight gas field. To maintaing the confidentiality of data and to showcase only the technical aspect of the workflow, we will refer to the asset as Field A in subsequent sections of this paper. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs. The study involved comparing analytical fracture modeling, explicit modeling using local grid refinements, tartan gridding, pseudo-well connection approach and full-field unconventional fracture modeling. The result of the study was to use, for the first time for Field A, a system of generating pseudo well connections to simulate hydraulic fractures. The approach was found to be efficient both terms of replicating field data for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.

Achieving Cementing Improvement in Horizontal Tight Gas Field Development

2015 ◽  
Author(s):  
Pungki Ariyanto ◽  
Mohamed.A.. A. Najwani ◽  
Yaseen Najwani ◽  
Hani Al Lawati ◽  
Jochen Pfeiffer ◽  
...  
Keyword(s):  
Tight Gas ◽  
Cement Slurry ◽  
Tight Sandstone ◽  
Gas Field ◽  
Full Field ◽  
Field Development ◽  
Horizontal Drain ◽  
Tight Reservoir ◽  
Design For All ◽  
Zonal Isolation

Abstract This paper outlines how a drilling team is meeting the challenge of cementing a production liner in deep horizontal drain sections in a tight sandstone reservoir. It is intended to show how the application of existing technologies and processes is leading to performance gain and improvements in cementing quality. The full field development plan of the tight reservoir gas project in the Sultanate of Oman is based on drilling around 300 wells targeting gas producing horizons at measured depths of around 6,000m MD with 1,000m horizontal sections. Effective cement placement for zonal isolation is critical across the production liner in order to contain fracture propagation in the correct zone. The first few attempts to cement the production liner in these wells had to overcome many challenges before finally achieving the well objectives. By looking at the complete system, rather than just the design of the cement slurry, the following criteria areas were identified: –Slurry design–Mud removal and cement slurry placement–Liner hanger and float equipment Improvements have been made in each of these areas, and the result has been delivery of a succesfully optimised liner cementing design for all future horizontal wells.

Achieving Cementing Improvement in Horizontal Tight Gas Field Development

2015 ◽  
Author(s):  
Pungki Ariyanto ◽  
Mohamed Ahmed Najwani ◽  
Yaseen Najwani ◽  
Hani Al Lawati ◽  
Jochen Pfeiffer ◽  
...  
Keyword(s):  
Tight Gas ◽  
Gas Field ◽  
Field Development

Ravenspurn South Field, Blocks 42/29, 42/30, 43/26, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 469-475 ◽  
Author(s):  
R. D. Heinrich
Keyword(s):  
North Sea ◽  
Reservoir Quality ◽  
Desert Environment ◽  
Gas Field ◽  
Field Development ◽  
Southern North Sea ◽  
Fluvial Processes ◽  
Sandstone Formation ◽  
Aeolian Sands

AbstractThe Ravenspurn South Gas Field is located in the Sole Pit Basin of the Southern North Sea in UKCS Block 42/30, extending into Blocks 42/29 and 43/26. The gas is trapped in sandstones of the Permian Lower Leman Sandstone Formation, which was deposited by aeolian and fluvial processes in a desert environment. Reservoir quality is poor, and variations are mostly facies-controlled. The best reservoir quality occurs in aeolian sands wth porosities of up to 23% and permeabilities up to 90 md. The trap is a NW-SE-striking faulted anticline: top seal is provided by the Silverpit Shales directly overlying the reservoir, and by Zechstein halites. Field development began early in 1988 and first gas was delivered in October 1989. Production is in tandem with the Cleeton Field, about 5 miles southwest of Ravenspurn South, as the Villages project. Initial reserves are 700 BCF and field life is expected to be 20 years.

scholarly journals Classification and Application of Tight Gas Wells Based on Cluster Analysis

2021 ◽  
Vol 2095 (1) ◽  
pp. 012099
Author(s):  
Zhenhua Cai ◽  
Chuanshuai Zuo ◽  
Jianying Zhu ◽  
Peng Qin ◽  
Baojiang Duan ◽  
...  
Keyword(s):  
Liquid Medium ◽  
High Energy ◽  
Low Energy ◽  
Production Performance ◽  
Tight Gas ◽  
Medium Energy ◽  
Gas Wells ◽  
Gas Field ◽  
Gas Well ◽  
Production Characteristics

Abstract The tight gas field is greatly affected by pressure in the development process. Due to the different production time and formation pressure of each well in the gas field, the production characteristics of the gas well are obviously different. After the gas well sees water, it is impossible to formulate production measures efficiently and accurately. Therefore, by analyzing the production performance characteristics of gas wells, this paper carries out the classification research of tight gas wells, and formulates the corresponding production measures according to the classification results. Taking gas well energy and liquid production intensity as the reference standard of gas well classification, the dynamic parameter indexes characterizing gas well energy and liquid production intensity are established. Gas wells with different production characteristics are divided into six categories by clustering algorithm: high energy-low liquid, high energy-high liquid, medium energy-low liquid, medium energy high-liquid, low energy-low liquid, low energy-high liquid. Then the classification method of tight gas well is formed. In this paper, 50 wells in Linxing block are selected as the research object. The research results show that most of the wells in Linxing block are located in area V, belonging to low energy and low liquid wells. It is recommended to implement intermittent production. The classification based on gas well energy and liquid production intensity are of guiding significance for the formulation of production measures in the Linxing block.

Factors controlling tight gas sandstone reservoir quality in the Whicher Range gas field, Southern Perth Basin, Western Australia

2011 ◽  
Vol 51 (2) ◽  
pp. 741
Author(s):  
Cesar Orsini ◽  
Reza Rezaee ◽  
Moyra Wilson
Keyword(s):  
Western Australia ◽  
Tectonic Setting ◽  
Flood Plain ◽  
Reservoir Rock ◽  
Coarse Grained ◽  
Reservoir Quality ◽  
Tight Gas ◽  
Gas Field ◽  
Sandstone Reservoir ◽  
Tight Gas Sandstone

There are limited studies characterising the Willespie Formation, a Permian tight gas sandstone in the southern Perth Basin of Western Australia. Consequently, the main factors controlling the reservoir quality, lateral reservoir connectivity and fluid flow mechanism remain unknown. Available data from five Whicher Range wells—including wireline logs, seismic, core data, well reports and petrographic data—were studied to define the syn-depositional and post-depositional events affecting the reservoir rock quality. Based on analysis of the aforementioned data, the Willespie Formation is interpreted to have been deposited under predominantly fluvial conditions in an ancient rift basin of continental origin with no marine influence. The sedimentary environments were laterally varied, as inferred from discontinuous facies formed by meandering channels, crevasse splay and flood plain settings that were mainly controlled by the Permian tectonic setting. Extensive compaction due to ductile grain deformation, as well as clay and calcite cements—filling pores and replacing grains—are the main post-depositional factors affecting the reservoir quality of the medium–coarse-grained, poorly sorted litharenitic sandstones of the Willespie Formation. Combined syn-depositional parameters—controlling the composition and the texture of the sandstone—and post-depositional diagenetic events have had a critical control on the distinctive poor porosity (8% average) and very low permeability of this tight gas sandstone reservoir.

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