Use of Exclusion Zones in Mapping and Modeling Fracture Corridors

2010 ◽  
Vol 13 (04) ◽  
pp. 679-687 ◽  
Author(s):  
Sait I. Ozkaya
Keyword(s):  
Distance Matrix ◽  
Well Testing ◽  
Well Test ◽  
Exclusion Zone ◽  
Fracture Permeability ◽  
Reservoir Evaluation ◽  
Lost Circulation ◽  
Matrix Permeability ◽  
Water Breakthrough ◽  
Well Tests

Summary Fracture corridors are fault-related, subvertical, tabular fracture clusters that traverse the entire reservoir vertically and extend for several tens or hundreds of meters horizontally. Conductive fracture corridors may have significant permeability and may profoundly affect reservoir-flow dynamics. Therefore, it is important to map conductive fracture corridors deterministically for reservoir evaluation and well planning. Deterministic mapping of fracture corridors requires locating fracture corridors and assigning to them length, orientation, fluid conductivity, and connectivity. Estimation of orientation, length, and—especially—connectivity is a major challenge in fracture-corridor mapping. An exclusion zone is a region that cannot have a conductive fault or fracture corridor passing through. Borehole images, open-hole logs, flow profiles, and lost-circulation data can be used to identify horizontal wells with no fracture-corridor intersection. Well tests, production/injection history, Kh ratio (permeability times thickness) well-test/core ratio, first water arrival, and oil-column-thickness maps can be used to identify vertical “matrix” wells that do not intersect fracture corridors. Adjacent matrix wells may be surrounded by inferred exclusion zones. The confidence level of inferred exclusion zones depends on factors such as interwell distance, matrix permeability, width, orientation, and spacing of fracture corridors. Overlapping of exclusion zones from independent data sources such as well testing and oil-column thickness have higher confidence than non-overlapping zones. Only borehole images provide orientation and only well tests provide length of fracture corridors. In the absence of well testing and borehole imaging, exclusion zones provide constraints and aid both in locating fracture corridors and assigning them orientation and length. Perhaps the most significant contribution of exclusion zones to fracture-corridor mapping is in identifying interconnected and isolated fracture corridors. An interconnected network of fracture corridors may extend laterally for several kilometers as major fracture permeability pathways, which not only improve pressure support, bottom upsweep of oil, but also cause rapid water breakthrough.

A Novel Well Test Data Analyzer and Process Optimizer Using Artificial Intelligence and Machine Learning Techniques

2021 ◽  
Author(s):  
Nagaraju Reddicharla ◽  
Subba Ramarao Rachapudi ◽  
Indra Utama ◽  
Furqan Ahmed Khan ◽  
Prabhker Reddy Vanam ◽  
...  
Keyword(s):  
Artificial Intelligence ◽  
Machine Learning ◽  
Real Time ◽  
Test Data ◽  
Oil Field ◽  
Well Testing ◽  
Well Test ◽  
Time Data ◽  
Real Time Data ◽  
Well Tests

Abstract Well testing is one of the vital process as part of reservoir performance monitoring. As field matures with increase in number of well stock, testing becomes tedious job in terms of resources (MPFM and test separators) and this affect the production quota delivery. In addition, the test data validation and approval follow a business process that needs up to 10 days before to accept or reject the well tests. The volume of well tests conducted were almost 10,000 and out of them around 10 To 15 % of tests were rejected statistically per year. The objective of the paper is to develop a methodology to reduce well test rejections and timely raising the flag for operator intervention to recommence the well test. This case study was applied in a mature field, which is producing for 40 years that has good volume of historical well test data is available. This paper discusses the development of a data driven Well test data analyzer and Optimizer supported by artificial intelligence (AI) for wells being tested using MPFM in two staged approach. The motivating idea is to ingest historical, real-time data, well model performance curve and prescribe the quality of the well test data to provide flag to operator on real time. The ML prediction results helps testing operations and can reduce the test acceptance turnaround timing drastically from 10 days to hours. In Second layer, an unsupervised model with historical data is helping to identify the parameters that affecting for rejection of the well test example duration of testing, choke size, GOR etc. The outcome from the modeling will be incorporated in updating the well test procedure and testing Philosophy. This approach is being under evaluation stage in one of the asset in ADNOC Onshore. The results are expected to be reducing the well test rejection by at least 5 % that further optimize the resources required and improve the back allocation process. Furthermore, real time flagging of the test Quality will help in reduction of validation cycle from 10 days hours to improve the well testing cycle process. This methodology improves integrated reservoir management compliance of well testing requirements in asset where resources are limited. This methodology is envisioned to be integrated with full field digital oil field Implementation. This is a novel approach to apply machine learning and artificial intelligence application to well testing. It maximizes the utilization of real-time data for creating advisory system that improve test data quality monitoring and timely decision-making to reduce the well test rejection.

Properties of a Natural Fracture and Its Skins From Reservoir Well Tests

SPE Journal ◽  
2013 ◽  
Vol 19 (03) ◽  
pp. 390-397 ◽  
Author(s):  
M.. Prats ◽  
R.. Raghavan
Keyword(s):  
History Matching ◽  
Flow Resistance ◽  
Short Interval ◽  
Natural Fracture ◽  
Disperse Flow ◽  
Well Test ◽  
Transient Pressure ◽  
Matrix Permeability ◽  
Wide Range ◽  
Well Tests

Summary Two well tests are described that are aimed at the in-situ determination of the flow capacity (permeability-thickness product) of a natural fracture and the flow resistance of its skins at the boundaries with the reservoir matrix. Fracture skins tend to disperse flow, thus affecting the distribution of tracers in reservoir tests and contaminants and trace elements in aquifers. We are unaware of any other analytical procedure aimed at obtaining the properties of a natural fracture and its skins from subsurface measurements. Neither well test has been implemented. The well tests are modeled after previously reported analytical expressions for the transient pressure distributions in a three-region composite reservoir in a uniform-thickness reservoir in which (1) the natural fracture is represented by a thin middle region of relatively high permeability, (2) the pressure disturbance is caused by producing from a short interval in one of the outer regions, and (3) the response is measured relatively near the fracture. The source and sensor may be on the same side or on opposite sides of the fracture, distinguishing the two tests. Visualizing special completions in a horizontal well intersecting a natural fracture normally, pressure responses are given for both tests for a wide range of fracture/matrix permeability ratios and skin flow resistances for a source 190 ft from the fracture and 10 ft from the sensor and on either side of the fracture, both at the midplane of the reservoir. A simple graphical procedure, not intended to replace history matching or regression where field data are available, illustrates how the two unknowns—permeability-thickness product of a natural fracture and the flow resistance of its skins—may be estimated from two representative values of an assumed measured pressure response.

Application of Tubing Stem Test as Alternative Low-Cost Solution for Dynamic Reservoir Evaluation: Case Study from Appraisal Well in Offshore Malaysia

2021 ◽  
Author(s):  
Adhi Naharindra ◽  
Mohd Hisham Abd Hamid ◽  
A Ghafar A Halim ◽  
Sarah M Affandi ◽  
W M W Ibrahim ◽  
...  
Keyword(s):  
Produced Water ◽  
Low Cost ◽  
Integrated Approach ◽  
Design Stage ◽  
Test Design ◽  
Test Duration ◽  
Well Testing ◽  
Well Test ◽  
Testing Program ◽  
Reservoir Evaluation

Abstract This paper demonstrate a unique combination of techniques and equipment that enabled dynamic reservoir evaluation process using simplified Drill Stem Test (DST) string and completion accessories. The well testing was conducted on a shallow slanted offshore well, drilled into faulted reservoirs with multilayer and complex fluids environment. Key technical challenges to perform well testing includes designing a custom DST string to cater for the multilayer reservoir and articulating a surface well testing equipment that capable of efficient separation to ensure safe and environmental friendly disposal while having accurate flowrate measurements, to deliver good interpretable data given that the uncertainty and complexity of the formation and the well itself. During drilling campaign, contingency plan to mitigate against losses was implemented which had a significant impact on the well testing program. As such, uncertainty-based well test design and interpretation methodology was used to address this and to achieve well objectives. This involved numerical model analysis considering reservoir uncertainties and their interaction with each other, to identify which parameters can be interpret confidently and to indicate the test duration for the well testing program. Since the area is nearby to producing fields, several cases model based on reservoir pressure regime was also constructed during the design stage to tolerate flexibilities for the decision tree. The well testing was successfully conducted result from integrated approach to well test design and realtime data support throughout the operation along with innovative DST string design, customize completion accessories for multiple zones testing and adaptive intervention tools for highly deviated well. Matching with nearby wells were also conducted during monitoring to predict future pressure behaviour which allow for the duration of final build-up to be optimized. Given that Health, Safety and Environment (HSE) is the top of priority, an important aspect of the surface well testing package was the water treatment equipment to treat the produced water from reservoir before being discharge in order to guarantee safe environmental disposal. The well was successfully test at maximum flowrate 2,000bpd of oil and 20MMscf/d of gas with traces of produced water. Data gathered thru the Tubing Stem Test (TST) can used to interpret reservoir parameters and all the well testing objectives were successfully achieved despite the many challenges encountered during the drilling campaign and design stage. The end results may contradict traditional testing methods for pressure transient analysis, but hopefully this paper might create the opportunity to replicate TST as quick and effective reservoir evaluation in other parts of the world.

Optimized Multi-Zone Dynamic Reservoir Evaluation in the Middle Caspian

2021 ◽  
Author(s):  
Sergey Shtun ◽  
Yermek Kaipov ◽  
Fanise Kamalov ◽  
Beibit Akbayev ◽  
Vlad Blinov
Keyword(s):  
Middle Part ◽  
Well Testing ◽  
Well Test ◽  
Reservoir Evaluation ◽  
Drilling Rig ◽  
Construction Design ◽  
Geological Conditions ◽  
Open Hole ◽  
Downhole Tool ◽  
Completion Fluids

Abstract Caspian offshore is reach for hydrocarbon reserves. The fields are made of multi-zone carbonate and sandstone reservoirs with significant variation of properties having high pressure (HP), high temperature (HT) and high H2S concentration in reservoir fluid. These challenges pose significant challenges to conduct the formation and multi-zone reservoir testing in a safe and informative manner. The dynamic reservoir evaluation program consists of formation pressure and its profile measurements, fluid pump-out for confirming the fluid type and sampling performed with wireline formation testers (FT) in open-hole and multi-zone well test for productivity estimation with drill-stem test (DST) designed for offshore environment with HP and high H2S. The project was planned and executed in an integrated manner, where the well construction design and selection of drilling and completion fluids has to improve the chance of success for FT and DST by taking into accound the downhole tool sizes and complex geological conditions. The open-hole formation testing and well testing in cased-hole were combined to provide enough information for characterizing multi-zone reservoirs by minimizing the drilling rig time. The well testing program was optimized in terms of number of zones for testing and necessity to acidize the reservoir based on formation testing data. The given methodolgy allowed to efficiently conduct the formation testing and well testing at two recently drilled offshore wells with multi-zone reservoirs. It was the first integrated dynamic reservoir evaluation project for such complex geological conditions in Middle part of Caspian offshore. This paper demonstrates the lessons learnt from two wells and offers the methodology for planning the evaluation for similar fields.

scholarly journals A new fracture permeability model of CBM reservoir with high-dip angle in the southern Junggar Basin, NW China

2018 ◽  
Vol 37 (1) ◽  
pp. 125-143 ◽  
Author(s):  
Shiyu Yang ◽  
Yidong Cai ◽  
Ren Wei ◽  
Yingfang Zhou
Keyword(s):  
Coalbed Methane ◽  
Junggar Basin ◽  
Well Testing ◽  
Well Test ◽  
Fracture Permeability ◽  
Permeability Model ◽  
Fracture Porosity ◽  
Nw China ◽  
Coalbed Methane Reservoir ◽  
Dip Angle

Predicting the permeability of coalbed methane (CBM) reservoirs is significant for coalbed methane exploration and coalbed methane development. In this work, a new fracture permeability model of coalbed methane reservoir with high-dip angle in the southern Junggar Basin, NW China is established based on the Poiseuille and Darcy laws. The fracture porosity in coalbed methane reservoir is calculated by applying 3D finite element method. The formation cementing index m was calculated by combining fractal theory and the data of acoustic logging, compensated neutron logging, and density logging with the space method. Based on Poiseuille and Darcy laws, the curvature τ is introduced to derive this new method for obtaining the permeability of the original fractures in coalbed methane reservoirs. Moreover, this newly established permeability model is compared with the permeability from the well testing, which shows a very good correlation between them. This model comprehensively includes the effects of fracture porosity, reservoir pore structure, and development conditions on fracture permeability. Finally, the permeability prediction of coalbed methane reservoir with high-dip angle in the southern Junggar Basin, NW China is conducted, which correlates very well with the well test permeability ( R2 = 0.83). Therefore, this model can be used to accurately predict the coalbed methane reservoir permeability of low rank coals in the southern Junggar Basin. The permeability of the No.43 coalbed methane reservoir for the coalbed methane wells without well testing data is evaluated, which ranges from 0.000251 to 0.379632 mD. This significant change in permeability may indicate a complex coalbed methane reservoir structure in the southern Junggar Basin, NW China.

The Role of Well Testing in Recognizing Deferred Production Revenue

2004 ◽  
Vol 126 (3) ◽  
pp. 177-183 ◽  
Author(s):  
P. Mehdizadeh ◽  
D. T. Perry
Keyword(s):  
Measurement Technology ◽  
Well Testing ◽  
Test Results ◽  
Well Test ◽  
Optimum Period ◽  
Well Tests ◽  
The Cost ◽  
Improved Accuracy ◽  
Allocation Factor

Well testing is routinely performed to evaluate the performance of a well, which establishes the allocation factor for the lease, which in turn establishes tax and royalty basis. Most well testing is done with conventional gravity separators, which separates the produced stream into oil, water, and gas components and measures these individual components as individual streams. New multiphase measurement technology improves well test results through improved accuracy, consistency, and more frequent well testing. This paper examines the implication of these improved capabilities to recognize well problems and optimize production. A simple economic model is provided that an operator can use to assess the balance between the cost of performing periodic well tests and the benefits of more quickly discovering well problems that can result in less than expected production. The model relates the cost of decreased production, as the result of unforeseen changes in the well, to the frequency and accuracy of the well tests. The model derives an optimum test interval that minimizes the total cost of well testing and deferred production on the basis of the probability that a higher than normal decline in production rate can be detected by well testing. The model is then used in several field examples to assess the optimum period between well tests and how the optimum period can lead to reduced cost of operation and improved production.

Extensive Well-Testing Operations Provide Insight Into Khuff Reservoirs

2021 ◽  
Vol 73 (02) ◽  
pp. 52-53
Author(s):  
Chris Carpenter
Keyword(s):  
Production Performance ◽  
Abu Dhabi ◽  
Well Testing ◽  
Well Test ◽  
Natural Fractures ◽  
Apparent Lack ◽  
Petrophysical Analysis ◽  
Wide Range ◽  
Well Tests ◽  
Insight Into

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203441, “Lessons Learned From Extensive Well-Testing Operations in Khuff Formations Offshore Abu Dhabi,” by Florian Hollaender, SPE, Schlumberger, and Mahmoud Basioni and Ahmed Yahya Al Blooshi, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. An extensive appraisal campaign was performed in the Khuff reservoirs offshore Abu Dhabi, with multiple appraisal wells drilled in different fields. Those wells were evaluated using detailed logging campaigns and then subjected to well tests, usually through drillstem testing for targeted intervals. The interpretation of well tests, combined with advanced petrophysical analysis, formation-test data, and production logs, provided insight into the nature of the Khuff reservoirs. A wide range of responses was observed, from tight to highly productive, but not necessarily with clear previous indications of deliverability or inflow intervals. Overview of the Khuff Formations The key characteristics of the Khuff formations offshore Abu Dhabi have been well-documented in previous work and can be summarized by the following: Low porosity and permeability carbonate reservoirs, where natural fractures are critical contributors to flow Properties vary widely laterally, with significant uncertainty regarding connectivity Variations in stress and petrophysical properties can be significant and affected by diagenetic and tectonic history These reservoirs present significant challenges for development planning. Previous studies have shown that it can be difficult to relate production performance to standard petrophysical analysis directly and that the presence of fractures - in particular, critically stressed fractures - in the vicinity of the wellbore is an essential factor for production performance. Productivity also was found to vary by several orders of magnitude within the same reservoir depending on the field and lateral location of a given well. The presence of natural fractures has been recognized as a major contributor to flow in tight gas reservoirs; however, this raises several questions related to assessing formation potential. First, the nature of the fractures must be evaluated. Some will contribute to production, while others will remain sealed. Equally importantly, identifying zones with promising porosity developments is not a solid indicator of production expectations. Well-Test Observations With more than 20 drillstem tests performed in the Khuff reservoirs during a 4-year period, the first observation is the wide range of reservoir responses encountered, with an apparent lack of consistency within a given reservoir or field.

The Role of Well Testing in Recognizing Deferred Production Revenue

2002 ◽  
Author(s):  
P. Mehdizadeh ◽  
D. T. Perry
Keyword(s):  
Measurement Technology ◽  
Well Testing ◽  
Test Results ◽  
Well Test ◽  
Optimum Period ◽  
Well Tests ◽  
The Cost ◽  
Improved Accuracy ◽  
Allocation Factor

Well testing is routinely performed to evaluate the performance of a well, which establishes the allocation factor for the lease, which in turn establishes tax and royalty basis. Most well testing is done with conventional gravity separators, which separates the produced stream into oil, water, and gas components and measures these individual components as individual streams. New multiphase measurement technology improves well test results through improved accuracy, consistency, and more frequent well testing. This paper examines the implication of these improved capabilities to recognize well problems and optimize production. A simple economic model is provided that an operator can use to assess the balance between the cost of performing periodic well tests and the benefits of more quickly discovering well problems that can result in less than expected production. The model relates the cost of decreased production, as the result of unforeseen changes in the well, to the frequency and accuracy of the well tests. The model derives an optimum test interval that minimizes the total cost of well testing and deferred production on the basis of the probability that a higher than normal decline in production rate can be detected by well testing. The model is then used in several field examples to assess the optimum period between well tests and how the optimum period can lead to reduced cost of operation and improved production.

A Back Allocation Methodology to Estimate the Real-Time Flow and Assist Production Monitoring

2021 ◽  
Author(s):  
Gabriela Chaves ◽  
Danielle Monteiro ◽  
Virgilio José Martins Ferreira
Keyword(s):  
Real Time ◽  
Input Data ◽  
Oil Field ◽  
Well Testing ◽  
Well Test ◽  
Time Data ◽  
Time Flow ◽  
Well Model ◽  
Operational Information ◽  
The Individual

Abstract Commingle production nodes are standard practice in the industry to combine multiple segments into one. This practice is adopted at the subsurface or surface to reduce costs, elements (e.g. pipes), and space. However, it leads to one problem: determine the rates of the single elements. This problem is recurrently solved in the platform scenario using the back allocation approach, where the total platform flowrate is used to obtain the individual wells’ flowrates. The wells’ flowrates are crucial to monitor, manage and make operational decisions in order to optimize field production. This work combined outflow (well and flowline) simulation, reservoir inflow, algorithms, and an optimization problem to calculate the wells’ flowrates and give a status about the current well state. Wells stated as unsuited indicates either the input data, the well model, or the well is behaving not as expected. The well status is valuable operational information that can be interpreted, for instance, to indicate the need for a new well testing, or as reliability rate for simulations run. The well flowrates are calculated considering three scenarios the probable, minimum and maximum. Real-time data is used as input data and production well test is used to tune and update well model and parameters routinely. The methodology was applied using a representative offshore oil field with 14 producing wells for two-years production time. The back allocation methodology showed robustness in all cases, labeling the wells properly, calculating the flowrates, and honoring the platform flowrate.

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