Downhole Monitoring of Fractures in a Waterflood Development – Part 1

2021 ◽  
Author(s):  
Abhinandan Kohli ◽  
Oscar Kelder ◽  
Maxim Volkov ◽  
Rita-Michel Greiss ◽  
Natalia Kudriavaya ◽  
...  
Keyword(s):  
High Pressures ◽  
Integrated Approach ◽  
Fracture Network ◽  
Acoustic Monitoring ◽  
Well Performance ◽  
Regulatory Requirements ◽  
Injection Wells ◽  
Significant Saving ◽  
Initiation Point ◽  
Seal Integrity

Abstract When an oilfield is exploited by simply producing oil and gas from a number of wells, the reservoir pressure in many circumstances drops quicker than normal impacting the production rates (Koning, 1988) and well performance. To maintain the pressures in the oil producing formations, waterflooding enhancement method is implemented by the Operators. This is achieved by drilling injection wells or converting the oil producing wells into injectors. The injection wells are located at carefully selected points in the oilfield so that the water displaces as much oil as possible to the production wells before the water starts to break through. A significant saving in an oilfield development can be obtained by reducing the actual number of injecting wells and increasing each of the injector wells' capacity for injection. Balancing the injection and produced volumes often involves injecting at high pressures leading to the fracture of the reservoir rocks along a plane intersecting the wellbore. This happens when injection pressure overcomes the rock stress and its tensile strength, thereby creating an induced fracture network. With continuous injection, these fractures start propagating into the reservoir and may reach the reservoir caprock. Continuing to inject further in such a fracture system may breach the top seal integrity of the caprock leading to uncontrolled out of zone injection. The study of evaluation of downhole fracture monitoring is divided into two parts. In this paper a downhole verification approach to identify the fracture initiation point(s) is the focus. It describes the planning, execution and interpretation of the downhole data. This includes spectral acoustic monitoring and modelling of the temperature responses to quantify the injectivity profile. In paper (Kohli, Kelder, Volkov, Castelijns, & van Eijs, 2021), the direct business impact and regulatory requirements are discussed by further integration of acoustic monitoring and temperature modeling data with detailed results from downhole measurements of fracture dimensions by means of pressure fall off tests. Combined, both studies form the integrated approach that the Operator took to meet the regulatory requirements proving that the fracture network propagation remains within the reservoir and that the top seal integrity is maintained.

Downhole Monitoring of Fractures in a Waterflood Development – Part II

2021 ◽  
Author(s):  
Abhinandan Kohli ◽  
Oscar Kelder ◽  
Ralph Castelijns ◽  
Rob van Eijs ◽  
Maxim Volkov
Keyword(s):  
Oil Recovery ◽  
High Pressures ◽  
Injection Pressure ◽  
Integrated Approach ◽  
Acoustic Monitoring ◽  
Height Measurement ◽  
Injection Wells ◽  
Significant Saving ◽  
Initiation Point ◽  
Seal Integrity

Abstract For maintenance of the reservoir pressures and enhanced oil recovery in oil producing formations, waterflooding is often implemented by the Operators. This is achieved by drilling injection wells or converting the oil producing wells into injectors. The injection wells are located at carefully selected points in the oilfield so that the water displaces as much oil as possible to the production wells before the water starts to break through. A significant saving in an oilfield development can be obtained by reducing the actual number of injecting wells and increasing each of the injector wells’ capacity for injection. Balancing the injection and produced volumes often involves injecting at high pressures leading to the fracture of the reservoir rocks along a plane intersecting the wellbore. This happens when injection pressure exceeds the minimal principal stress and the tensile strength of the rock, thereby creating a hydraulic fracture. With continuous injection, these fractures start propagating into the reservoir and may reach the reservoir caprock, which may decrease the integrity and possibly lead to out of zone injection. The study of evaluation of downhole fracture monitoring is divided into two parts. In the first part of the paper (Kohli, et al., 2021), a downhole verification approach to identify the fracture initiation point(s) is the focus. It describes the planning, execution and interpretation of the downhole data. This includes spectral acoustic monitoring and modelling of the temperature responses to quantify the injectivity profile. In this second part of the paper, the direct business impact is discussed by further integration of acoustic monitoring and temperature modeling data with detailed results from of fracture dimension (height) measurement by means of pressure fall off tests. Combined, both studies form an integrated approach that the operator took to prove that the fracture network propagation remains within the reservoir and that the top seal integrity is maintained.

Pipeline Corrosion Integrity Management by Direct Assessment

2015 ◽  
Author(s):  
Shailesh Javia
Keyword(s):  
Integrated Approach ◽  
Assessment Process ◽  
Regulatory Requirements ◽  
Integrity Assessment ◽  
Advantages And Disadvantages ◽  
Direct Assessment ◽  
Pipeline Segment ◽  
Integrity Management ◽  
Post Assessment ◽  
Pipeline Corrosion

Integrity management of pipelines is a systematic, comprehensive and integrated approach to proactively counter the threats to pipeline integrity. Pressure testing, in-line inspection and direct assessment methods are used to verify the integrity of a buried pipeline. The Paper Discuses Direct Assessment Methodologies for Hydrocarbon Non Piggable Pipelines. Advantages and Disadvantages of Direct Assessment methodology and DA Protocols. The DA process accomplishes this by utilizing and integrating condition monitoring, effective mitigation, meticulous documentation and timely structured reporting processes. DA is a structured, iterative integrity assessment process through which an operator may be able to assess and evaluate the integrity of a pipeline segment. TIME DEPENDENT THREATS INEVITABLY LED TO NUMEROUS FAILURES WITH A COMMON DEFINING MECHANISM OR SOURCE – CORROSION. This Paper will focus on internal, external and stress corrosion cracking direct assessment along with pre and post assessment, quality assurance, data analysis and integration, and remediation and mitigation activities. This paper will discuss some of the regulatory requirements for Pipeline Integrity Management System.

The New Generation of Outflow Control Devices Autonomously Controlling the Conformance of Water Injection Well- A Case Study with ADNOC Onshore

2021 ◽  
Author(s):  
Sultan Ibrahim Al Shemaili ◽  
Ahmed Mohamed Fawzy ◽  
Elamari Assreti ◽  
Mohamed El Maghraby ◽  
Mojtaba Moradi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Dynamic Properties ◽  
Short Circuit ◽  
Water Injection ◽  
Performance Outcomes ◽  
Injection Well ◽  
Well Performance ◽  
Injection Wells ◽  
Horizontal Section ◽  
Control Devices

Abstract Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close. Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance. A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained. This paper presents the results from one of the early installations of the valves in a water injection well in the Middle East for ADNOC onshore. The paper discusses the applied completion design workflow as well as some field performance and PLT data.

Evaluating Infill Well Performance and Fracture Driven Interactions Using Intervention Based Distributed Fiber Optics

2021 ◽  
Author(s):  
Ahmed Attia ◽  
Matthew Lawrence
Keyword(s):  
Fiber Optics ◽  
Fracture Network ◽  
Data Sets ◽  
Well Performance ◽  
Design Strategies ◽  
Data Set ◽  
Geological Features ◽  
Production Output ◽  
Long Carbon Fiber ◽  
The Impact

Abstract Distributed Fiber Optics (DFO) technology has been the new face for unconventional well diagnostics. This technology focuses on measuring Distributed Acoustic Sensing (DAS) and Distrusted Temperature Sensing (DTS) to give an in-depth understanding of well productivity pre and post stimulation. Many different completion design strategies, both on surface and downhole, are used to obtain the best fracture network outcome; however, with complex geological features, different fracture designs, and fracture driven interactions (FDIs) effecting nearby wells, it is difficult to grasp a full understanding on completion design performance for each well. Validating completion designs and improving on the learnings found in each data set should be the foundation in developing each field. Capturing a data set with strong evidence of what works and what doesn't, can help the operator make better engineering decisions to make more efficient wells as well as help gauge the spacing between each well. The focus of this paper will be on a few case studies in the Bakken which vividly show how infill wells greatly interfered with production output. A DFO deployed with a 0.6" OD, 23,000-foot-long carbon fiber rod to acquire DAS and DTS for post frac flow, completion, and interference evaluation. This paper will dive into the DFO measurements taken post frac to further explain what effects are seen on completion designs caused by interferences with infill wells; the learnings taken from the DFO post frac were applied to further escalate the understanding and awareness of how infill wells will preform on future pad sites. A showcase of three separate data sets from the Bakken will identify how effective DFO technology can be in evaluating and making informed decisions on future frac completions. In this paper we will also show and discuss how DFO can measure real time FDI events and what measures can be taken to lessen the impact on negative interference caused by infill wells.

Is High Viscosity a Requirement for Fracturing Fluids?

2022 ◽  
Author(s):  
John E. Busteed ◽  
Jesus Arroyo ◽  
Francisco Morales ◽  
Mohammed Omer ◽  
Francisco E. Fragachan
Keyword(s):  
Injection Pressure ◽  
Fracture Network ◽  
High Viscosity ◽  
Network Simulator ◽  
Well Performance ◽  
Field Case ◽  
Temperature Conditions ◽  
Low Viscosity ◽  
Fracturing Fluids ◽  
Fracture Closure

Abstract Uniformly distributing proppant inside fractures with low damage on fracture conductivity is the most important index of successful fracturing fluids. However, due to very low proppant suspension capacity of slickwater and friction reducers fracturing fluids and longer fracture closure time in nano & pico darcies formations, proppants settles quickly and accumulates near wellbore resulting in worse-than-expected well performance, as the fracture full capacity is not open and contributing to production. Traditionally, cross-linked polymer fluid systems are capable to suspend and transport high loading of proppants into a hydraulically generated fracture. Nevertheless, amount of unbroken cross-linked polymers is usually left in fractures causing damage to fracture proppant conductivity, depending on polymer loading. To mitigate these challenges, a low viscosity-engineered-fluid with excellent proppantcarrying capacity and suspension-in excess of 30 hours at static formation temperature conditions - has been designed, enhancing proppant placement and distribution within developed fractures, with a 98% plus retained conductivity. In this work experimental and numerical tests are presented together with the path followed in developing a network of packed structures from polymer associations providing low viscosity and maximum proppant suspension. Challenges encountered during field injection with friction are discussed together with the problem understanding characterized via extensive friction loop tests. Suspension tests performed with up to 8-10 PPA of proppant concentration at temperature conditions are shared, together with slot tests performed. Physics-based model results from a 3D Discrete Fracture Network simulator that computes viscosity, and elastic parameters based on shear rate, allows to estimate pressure losses along the flow path from surface lines, tubular goods, perforations, and fracture. This work will demonstrate the advanced capabilities and performance of the engineered fluid over conventional fracturing fluids and its benefits. Additionally, this paper will present field injection pressure analysis performed during the development of this fluid, together with a field case including production results after 8 months of treatment. The field case production decline observed after fracture treatment demonstrates the value of this system in sustaining well production and adding additional reserves.

Recognition of Fracturing by Stimulated Reservoir Volume (SRV) in Shale Gas Wells

2011 ◽  
Vol 361-363 ◽  
pp. 349-352 ◽  
Author(s):  
Hui Hui Kou ◽  
Wei Dong Liu ◽  
Dong Dong Hou ◽  
Ling Hui Sun
Keyword(s):  
Fracture Network ◽  
Single Fracture ◽  
Well Performance ◽  
Stimulated Reservoir Volume ◽  
Fracture Length ◽  
Reservoir Volume ◽  
Tight Gas Sands ◽  
Well Pattern ◽  
Complex Fracture Network ◽  
Shale Reservoirs

Ultra-low permeability shale reservoir require a large fracture network to maximal well performance. In conventional reservoirs and tight gas sands, single fracture length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex fracture network are created, single fracture length and conductivity are insufficient to stimulate. This is the reason for the concept of using stimulated reservoir volume as a correlation parameter for well performance. This paper mainly illustrates perforation with interlaced row well pattern and multi-fracture fracturing technology and refracturing applied in vertical wells. Moreover, it establishes the seepage differential equation of multi-fracture.

The Ensign Field, Blocks 48/14a, 48/15a and 48/15b, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 172-179 ◽  
Author(s):  
V. W. J. Verlinden ◽  
H. Basford
Keyword(s):  
North Sea ◽  
Regional Scale ◽  
Fracture Network ◽  
Natural Fracture ◽  
Well Performance ◽  
Gas Recovery ◽  
Production Wells ◽  
Sandstone Formation ◽  
Low Offset

AbstractThe Ensign Field is located in UK offshore licence Blocks 48/14a, 48/15a and 48/15b. The field is located 100 km east of the Humberside coast within the Sole Pit area of the Southern North Sea. The reservoir consists of sandstones of the Permian Rotliegend Group (Leman Sandstone Formation). Reservoir quality has been impacted by diagenesis during deep burial, whereby illitization has reduced permeability to sub-millidarcy scale. The field has been developed with two horizontal production wells, both completed with five hydraulic fracture stages. First gas from the field was achieved in 2012 via the Ensign normally unmanned installation and exported through the Lincolnshire Offshore Gas Gathering System. The field is compartmentalized by multiple regional-scale De Keyser fault zones. A heterogeneous natural fracture network exists with only a limited contribution to flow. Well performance and ultimate gas recovery have been lower than originally anticipated due to sub-optimal completions and a higher degree of compartmentalization than originally expected. The volume of gas that is connected to the wells is limited by low-offset faults, which have been identified by integrating long-term production data, and core, log and reprocessed seismic data. Production ceased in 2018 when the original export route was decommissioned.

De-Risking Thermal Induced Sustained Annulus Pressure to Safeguard Optimal Production

2021 ◽  
Author(s):  
Sunday Maxwell-Amgbaduba ◽  
David Ogbonna ◽  
Femi Obakhena ◽  
Onyedikachi Okereke ◽  
Ihuoma Green ◽  
...  
Keyword(s):  
Thermal Expansion ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Acoustic Monitoring ◽  
Pressure Monitoring ◽  
Passive Acoustic Monitoring ◽  
Seal Integrity ◽  
System Integrity ◽  
Passive Acoustic ◽  
Bean Size

Abstract Sustained Annulus Pressure (SAP) is a common production constraint in the oil and gas industry, it is usually caused by impaired seal Integrity within the wellbore system resulting in barrier failures. In peculiar scenarios the thermal expansion creates pressure build-up in the annulus as well which can equally impair the integrity of the wellbore. In this paper the results of downhole and surface pressure monitoring surveys are presented, the objectives aim at determination of both downhole leaks and verification the influence of thermal expansion into a wellbore system integrity in a field located onshore Niger Delta. SAP in a producing well was earlier recorded during routine annular pressure monitoring in 2017 during the production rate increase by changing the bean size from 18/64" to 24/64". Initial diagnostics observed pointed towards SAP resulting from a possible downhole seal integrity issue leading to a leak to the surface. While putting the well on stream with current bean size and the pressure regime for both THP and CHP was observed. Pressure with time analysis showed annulus pressure builds up rapidly while flowing and bleeds off within 30 min from 700 psi to 0 psi when well shut in. Downhole logging and sensitive passive acoustic monitoring was conducted, the survey aimed to detect barrier failures by capturing its acoustic leak patterns under shut-in and bleeding off condition. Considering the suspected leak behaviour, the data acquisition included the procedure to build up the annulus pressure by flowing the well and monitoring the annulus discharge. Integrity logs survey and passive acoustic monitoring confirmed there were no downhole failures and after several bleed-offs when Tubing choke was beaned down to 18/64" no annulus pressure build-up was observed from the Well head gauge on the Casing head confirming the source of the sustained annulus pressure is driven by the temperature expansion of the annulus fluid. Remedial action and recommendation after Simulation were to de-risk the well at a controlled bean size to mitigate SAP and optimally flow the well.

Numerical Simulation of Shale Gas Production

2011 ◽  
Vol 402 ◽  
pp. 804-807 ◽  
Author(s):  
Song Ru Mu ◽  
Shi Cheng Zhang
Keyword(s):  
Shale Gas ◽  
Simulation Models ◽  
Fracture Network ◽  
Gas Production ◽  
Wire Mesh ◽  
Well Performance ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs ◽  
Fracture Mapping

Shale gas reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. The application of microseismic fracture mapping measurements requires estimation of the structure of the complex hydraulic fracture or the volume of the reservoir that has been stimulated by the fracture treatment. There are three primary approaches used to incorporate microseismic measurements into reservoir simulation models: discrete modeling of the complex fracture network, wire-mesh model, and dual porosity model. This paper discuss the different simulation model, the results provided insights into effective stimulation designs and flow mechanism for shale gas reservoirs.

Peritoneal Dialysis: Better than, Equal to, or Worse than Hemodialysis? Data Worth Knowing before Choosing a Dialysis Modality

2001 ◽  
Vol 21 (1) ◽  
pp. 1-15 ◽  
Author(s):  
Elias Thodis ◽  
Ploumis Passadakis ◽  
Vassilis Vargemezis ◽  
Dimitrios G. Oreopoulos
Keyword(s):  
Peritoneal Dialysis ◽  
Membrane Damage ◽  
Integrated Approach ◽  
Dialysis Dose ◽  
Significant Saving ◽  
Technological Advances ◽  
Data Worth ◽  
Stage Renal Disease ◽  
End Stage ◽  
Esrd Patients

Technological advances such as those that allow the delivery of an adequate dialysis dose to a larger percentage of patients, minimization of peritoneal membrane damage with more biocompatible solutions, and lower peritonitis rates will undoubtedly improve retention of patients on peritoneal dialysis (PD) for longer periods. Currently, only 15% of the world dialysis population is managed by PD. Peritoneal dialysis has many advantages over hemodialysis, and if end-stage renal disease (ESRD) patients are fully informed about them, the proportion of patients who would prefer this treatment would rise to 25% – 30%. An integrated approach to the treatment of ESRD could start with PD in a large percentage of patients, especially those who will receive a kidney transplant within 2 – 3 years. With the present epidemic of ESRD, this approach could lead to a significant saving, relieve the pressure on dialysis units, and allow a larger number of ESRD patients to be treated.

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