The Impact of Effective Fracture Length versus Effective Fracture Height on Ultimate Recovery in Tight-Gas and Unconventional Reservoirs

2015 ◽  
Author(s):  
J. R. Shaoul ◽  
J. Park ◽  
K. van der Hoorn
Keyword(s):  
Unconventional Reservoirs ◽  
Tight Gas ◽  
Fracture Length ◽  
Fracture Height ◽  
The Impact

Utilizing Microseismic to Monitor Fracture Geometry in a Horizontal Well in a Tight Sandstone Formation

2021 ◽  
Author(s):  
Abu M. Sani ◽  
Hatim S. AlQasim ◽  
Rayan A. Alidi
Keyword(s):  
Horizontal Well ◽  
Fracture Propagation ◽  
Horizontal Stress ◽  
Height Growth ◽  
Tight Sandstone ◽  
Fracture Geometry ◽  
Fracture Length ◽  
Sandstone Formation ◽  
Fracture Height ◽  
Maximum Horizontal Stress

Abstract This paper presents the use of real-time microseismic (MS) monitoring to understand hydraulic fracturing of a horizontal well drilled in the minimum stress direction within a high-temperature high-pressure (HTHP) tight sandstone formation. The well achieved a reservoir contact of more than 3,500 ft. Careful planning of the monitoring well and treatment well setup enabled capture of high quality MS events resulting in useful information on the regional maximum horizontal stress and offers an understanding of the fracture geometry with respect to clusters and stage spacing in relation to fracture propagation and growth. The maximum horizontal stress based on MS events was found to be different from the expected value with fracture azimuth off by more than 25 degree among the stages. Transverse fracture propagation was observed with overlapping MS events across stages. Upward fracture height growth was dominant in tighter stages. MS fracture length and height in excess of 500 ft and 100 ft, respectively, were created for most of the stages resulting in stimulated volumes that are high. Bigger fracture jobs yielded longer fracture length and were more confined in height growth. MS events fracture lengths and heights were found to be on average 1.36 and 1.30 times, respectively, to those of pressure-match.

No Need for Radio Active Tracer When Mother Nature Helps Detecting the Effective Hydraulic Fracture Height

2022 ◽  
Author(s):  
Rinat Lukmanov ◽  
Said Jabri ◽  
Ehab Ibrahim
Keyword(s):  
Hydraulic Fracture ◽  
Natural Radioactivity ◽  
Gamma Ray ◽  
Fracture Propagation ◽  
Radioactive Isotopes ◽  
Main Element ◽  
Tight Gas ◽  
Well Test ◽  
Gas Reservoirs ◽  
Fracture Height

Abstract The tight gas reservoirs of Haima Supergroup provide the majority of gas production in the Sultanate of Oman. The paper discusses a possibility of using the anomalies from natural radioactivity to evaluate the fracture height for complex tight gas in mature fields of Oman. The standard industry practice is adding radioactive isotopes to the proppant. Spectral Gamma Ray log is used to determine near wellbore traced proppant placement. Spectral Noise log in combination with Production logs helps to identify the active fractures contributing to production. These methods complement each other, but they are obviously associated with costs. Hence, majority of wells are fracced without tracers or any other fracture height diagnostics. However, in several brown fields, an alternative approach to identify fracture height has been developed which provides fit-for-purpose results. It is based on the analysis of naturally occurring radioactive minerals (NORM) precipitation. The anomalies were observed in the many gas reservoirs even in cases when tracers were not used. At certain conditions, these anomalies can be used to characterize fracture propagation and optimize future wells hydraulic Fracture design. A high number of PLTs and well test information were analyzed. Since tight formations normally don't produce without fracturing, radioactive anomalies flag the contributing intervals and hence fracture propagation. The main element of analysis procedure is related to that fact that if no tracers applied, the discrepancy between normalized Open Hole Gamma Ray and Gamma Ray taken during PLT after 6-12 months of production can be used instead to establish fracture height. This method cannot be applied for immediate interpretation of fracture propagation because time is required to precipitate NORM and using the anomalies concept. The advantage of this method is that it can be used in some fields to estimate the frac effectiveness of wells without artificial tracers. It is normally assumed that the Natural radioactivity anomalies appear mainly due to co-production of the formation water. However, in the fields of interest the anomalies appear in wells producing only gas and condensate. This observation provides an opportunity for active fracture height determination at minimum cost.

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.

Understanding Unusual Diagnostic Fracture Injection Test Results in Tight Gas Fields - A Holistic Approach to Resolving the Data

2015 ◽  
Author(s):  
R.N.. N. Naidu ◽  
E.A.. A. Guevara ◽  
A.J.. J. Twynam ◽  
J.. Rueda ◽  
W.. Dawson ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Test Procedure ◽  
Holistic Approach ◽  
In Situ Stress ◽  
Lessons Learned ◽  
Petroleum Engineering ◽  
Tight Gas ◽  
Review Team ◽  
Gas Fields ◽  
The Impact

Abstract Hydraulic fracturing is a commonly used completion approach for extracting hydrocarbon resources from formations, particularly in those formations of very low permeability. As part of this process the use of Diagnostic Fracture Injection Tests (DFIT) can provide valuable information. When the measured pressures in such tests are outside the expected range for a given formation, a number of possibilities and questions will arise. Such considerations may include: What caused such inflated pressures? What is the in-situ stress state? Was there a mechanical or operational problem? Was the test procedure or the test equipment at fault? What else can explain the abnormal behaviour? While there may not be simple answers to all of these questions, such an experience can lead to a technically inaccurate conclusion based on inadequate analysis. A recently completed project faced just such a challenge, initially resulting in poor hydraulic fracturing efficiency and a requirement to understand the root causes. In support of this, a thorough analysis involving a multi-disciplinary review team from several technical areas, including petrophysics, rock/geo-mechanics, fluids testing/engineering, completions engineering, hydraulic fracture design and petroleum engineering, was undertaken. This paper describes the evolution of this study, the work performed, the results and conclusions from the analysis. The key factors involved in planning a successful DFIT are highlighted with a general template and a work process for future testing provided. The importance of appreciating the impact of the drilling and completion fluids composition, their properties and their compatibility with the formation fluids are addressed. The overall process and technical approach from this case study in tight gas fields, will have applicability across similar fields and the lessons learned could help unlock those reserves that are initially deemed technically or even commercially unattractive due to abnormal or unexpected behaviour measured during a DFIT operation.

Factor Analysis of Vertical Hydraulic Fracture Geometry in Coal Bed

2013 ◽  
Vol 316-317 ◽  
pp. 892-895 ◽  
Author(s):  
Bai Lie Wu ◽  
Yuan Fang Cheng ◽  
You Zhi Li ◽  
Peng Xu ◽  
Yu Ting Zhang
Keyword(s):  
Effective Means ◽  
Propagation Model ◽  
Coal Bed ◽  
Vertical Wells ◽  
Differential Stress ◽  
Fracture Geometry ◽  
Fracture Length ◽  
Treatment Conditions ◽  
Pump Rate ◽  
Fracture Height

Hydraulic fracturing is one of the effective means to enhance coal bed methane production for vertical wells. This paper presents an approach that uses pseudo-3D fracture propagation model to study the influence of petrophysical properties, differential stress, treatment conditions, etc. on fracture geometry. It is shown that differential stress, pump rate is proportional to fracture length and width; elastic modulus, Poisson`s ratio, pump rate, etc. is proportional to fracture height. The finding is of great importance for acquiring ideal fracture geometry.

Minimising the impact of shale and tight gas projects in Western Australia: an assessment of the existing regulatory framework

2014 ◽  
Vol 54 (1) ◽  
pp. 83
Author(s):  
Tina Hunter
Keyword(s):  
Best Practice ◽  
Legal Framework ◽  
Regulatory Framework ◽  
Tight Gas ◽  
Project Development ◽  
Commercial Development ◽  
Lead Agency ◽  
Western Australian Department ◽  
The Impact ◽  
Protection Authority

This paper analyses the WA legal framework that regulates the impact of shale and tight gas project development, especially during the extended appraisal phase. It assesses whether the existing regulatory framework in WA is more suited to conventional petroleum projects, particularly regarding the application of the Environmental Plan requirements, and triggers for referral to the Environmental Protection Authority (EPA) during the extended appraisal phase of project development. This paper not only seeks to understand whether the existing framework is suited to the commercial development of shale and tight gas resources in WA, it also provides information and points of discussion for industry and regulators so that there might be a consensus in the development of shale and tight gas (especially during the field appraisal and development phase) in the existing WA regulatory framework, and the development of shale gas resources in Australia generally. The paper initially considers the existing regulatory framework of shale and tight gas activities in WA, including an examination of the Western Australian Department of Mines and Petroleum as the lead agency in the development of unconventional gas resources. It also assesses whether the existing regulatory framework for shale and tight gas activities in WA is best practice for the appraisal phase of shale and tight gas activities.

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