A QUICK-LOOK EVALUATION OF THE SANDING POTENTIAL OF PRODUCTION WELLS IN THE YOLLA FIELD

2005 ◽  
Vol 45 (1) ◽  
pp. 77
Author(s):  
Z.J. Pallikathekathil ◽  
J.R. Marsden ◽  
R.J. Suttill ◽  
M. Mussared ◽  
L. Qiuguo
Keyword(s):  
Time Frame ◽  
Development Planning ◽  
Rock Properties ◽  
Earth Model ◽  
Well Test ◽  
Worst Case ◽  
Data Set ◽  
Field Development ◽  
Production Wells ◽  
Open Hole

The preliminary downhole completions and surface facilities for the Yolla field had been designed based on the well test results from the Yolla–1 well. This well had produced insignificant sand during production testing, but during the field development planning, there was a concern raised regarding the propensity of some zones to sand. If the zones were prone to sanding, then the design of completions and surface facilities would have to be re-worked on with steps taken to mitigate any sanding. Mitigation steps would include perforation strategy (selective zone perforation, oriented perforation), sand screen or gravel pack.Therefore, a quick-look evaluation of the sanding potential of the particular zones of interest was undertaken to be completed within the project time frame. The sand zones analysed were Sand–2718, –2755, –2809, and –2973 from the Eastern View Coal Measures(EVCM).Yolla–2 well had the most complete data set available. A mechanical earth model (MEM) containing information on rock properties, pressures and in-situ stresses was constructed based on open-hole log data from the Yolla–2 appraisal well. Laboratory tests provided some uni-axial compressive strength (UCS) data for calibration of the model. The MEM data were input into sanding analyses, for various reservoir depths and for selected completion and perforation options. Since some MEM parameters were poorly constrained, best- and worst-case scenarios and sensitivities were evaluated to assess the influence of geomechanical parameters on sanding propensity.When Yolla–3 and –4 were drilled, more complete sets of logs were acquired and used to improve confidence in the earlier evaluations, and to check the validity of certain assumptions that had been made. With revised evaluation for Yolla–3 and –4, decisions on the completion strategy and perforation intervals were taken and implemented in the field development planAfter completion, both Yolla–3 and Yolla–4 were tested and sanding rates were monitored. After initial transient production of sand during clean-up, sand rates produced were insignificant. This confirmed the results of the quicklook geomechanical analyses that had been conducted.

JOHN BROOKES GAS FIELD DEVELOPMENT

2005 ◽  
Vol 45 (1) ◽  
pp. 13
Author(s):  
A.J. McDiarmid ◽  
P.T. Bingaman ◽  
S.T. Bingham ◽  
B. Kirk-Burnnand ◽  
D.P. Gilbert ◽  
...  
Keyword(s):  
Low Cost ◽  
Time Frame ◽  
Gas Production ◽  
Gas Field ◽  
Initial Development ◽  
North West ◽  
Field Development ◽  
The North ◽  
Production Wells ◽  
Development Approach

The John Brookes gas field was discovered by the drilling of John Brookes–1 in October 1998 and appraisal drilling was completed in 2003. The field is located about 40 km northwest of Barrow Island on the North West Shelf, offshore West Australia. The John Brookes structure is a large (>90 km2) anticline with >100 m closure mapped at the base of the regional seal. Recoverable sales gas in the John Brookes reservoir is about 1 Tcf.Joint venture approval to fast track the development was gained in January 2004 with a target of first gas production in June 2005. The short development time frame required parallel workflows and use of a flexible/low cost development approach proven by Apache in the area.The John Brookes development is sized for off-take rates up to 240 TJ/d of sales gas with the development costing A$229 million. The initial development will consist of three production wells tied into an unmanned, minimal facility wellhead platform. The platform will be connected to the existing East Spar gas processing facilities on Varanus Island by an 18-inch multi-phase trunkline. Increasing the output of the existing East Spar facility and installation of a new gas sweetening facility are required. From Varanus Island, the gas will be exported to the mainland by existing sales gas pipelines. Condensate will be exported from Varanus Island by tanker.

Gamification in Training of Holistic Multidisciplinary Petroleum Asset Management

2021 ◽  
Author(s):  
Arthur Aslanyan ◽  
Arkady Popov ◽  
Rustem Asmandiyarov ◽  
Andrey Margarit
Keyword(s):  
Asset Management ◽  
Real Life ◽  
Development Planning ◽  
Well Test ◽  
Well Performance ◽  
Learning Program ◽  
Remote Communication ◽  
Well Drilling ◽  
Warm Up ◽  
Open Hole

Abstract The paper shares a 4-years’ experience of "Gazprom Neft" PJSC on Digital Twin Learning Program in training of holistic multidisciplinary petroleum asset management and engineering based on the on-line cloud PetroCup software facility. The objective of the program was to train and test large amounts of managers and engineers with minimum off-work time and motivate self-improvement among the employee. The program includes warm-up videos, immersive master-classes, training courses, discussion clubs and Annual Corporate Championship, with a strong focus on home learning, remote communication, simulation-based exercises and automated testing/certification. The program is divided into Master Development Planning (MDP) and Well & Reservoir Management (WRM) domains which are related to different stages of the petroleum asset lifecycle. The interaction with simulator takes 2-3 days for WRM and 5 days for MDP and engages a multidisciplinary team: asset manager, economist, contract engineer, surface facility engineer, reservoir engineer, geologist, petrophysicist, simulation engineer, well test engineer, well and log analyst and production technologist. The session starts by reading the existing field data and its history and then perform well drilling, completions, workovers, well tests, open-hole and cased-hole logging, manage production and injection targets, build/modify the surface production/injection facilities and receive the fully automated asset response in the form of the field reports, very much in the same way as in real life. Once session is over the simulator generates a detailed debriefing report on team performance in numerous areas: economical, production, injection, reservoir and well performance so that team can understand where it did a good job and where it was not efficient. The current paper shows how this facility has been integrated into the corporate staff capability program, expanded to anchor universities and shed the light to the future perspectives.

Bringing Flexibility and Automation to Well Testing Operations Through Wireless Telemetry - Case Study

2021 ◽  
Author(s):  
Elias Temer ◽  
Deiveindran Subramaniam ◽  
Yermek Kaipov ◽  
Carlos Merino ◽  
Vladimirovich Latvin ◽  
...  
Keyword(s):  
Real Time ◽  
Reservoir Characterization ◽  
Time Window ◽  
Weather Conditions ◽  
Development Planning ◽  
Testing Time ◽  
Well Testing ◽  
Well Test ◽  
Real Time Control ◽  
Field Development

Abstract Dynamic reservoir data are a key driver for operators to meet the forecasted production investments of their fields. However, many challenges during well testing, such as reduced exploration and capex budgets, complex geologic structures, and inclement weather conditions that reduce the well testing time window can prevent them from gathering critical reservoir characterization data needed to make more informed field development planning decisions. To overcome these challenges, a live, downhole reservoir testing platform enabled the most representative reservoir information in real time and connected more zones of interest in a single run for appraisal wells in the Sea of Okhotsk, Russia. This paper describes the test requirements, the prejob planning, and automated execution of wirelessly enabled operations that led to the successful completion of the well test campaign in very hostile conditions, a remote area, and restricted period. The use of a telemetry system to well testing in seven zones enabled real-time control of critical downhole equipment and acquired data at surface, which in turn was transmitted to the operator's office in town in real time. Various operation examples will be discussed to demonstrate how automated data acquisition and downhole operations control has been used to optimize operations by both the service company and the operator.

Reservoir Drilling, Completion and Breaker Fluid Qualification for Direct Injection Wells on the Johan Castberg Field – A Multi-Disciplinary Study to Secure Injectivity

2021 ◽  
Author(s):  
Charlotte Eliasson ◽  
Ove Braadland ◽  
Håvard Kaarigstad ◽  
Anne-Mette Mathisen ◽  
Zalpato Ibragimova ◽  
...  
Keyword(s):  
Filter Cake ◽  
Drilling Fluid ◽  
Direct Injection ◽  
Time Frame ◽  
Development Project ◽  
Fluid System ◽  
Injection Wells ◽  
Field Development ◽  
Fluid Systems ◽  
Open Hole

Abstract For the Johan Castberg field development project, injector wells are important for achieving high production and overall high recovery factors. Injectivity has become more important due to limitations in injection pressures and required control of fracture growth. Securing injectivity has been identified as one of the project’s main risks, making drill-in fluid and breaker fluid system qualification a vital parameter for success. Operational procedures and completion design also affect the effectiveness of breaker fluid placement and, thus, the overall injectivity of the well. In this paper, we present a cross-disciplinary systematic approach for the reservoir drill-in fluid and breaker fluid qualification to ensure injectivity in these wells. Two wells were selected for covering the expected pressure and temperature range of the field in an environmentally sensitive area. Two independent fluid systems were designed, where the bridging material consisted of either sized salt particles or calcium carbonate particles. The open hole completion design has been optimized for an effective breaker fluid placement, using a modified gravel pack system with a wash pipe. The displacement sequence has been optimized for effective deployment. An extensive laboratory test matrix for both the reservoir drilling fluid (RDF) and breaker fluid system was established, including thorough analysis of the interaction between the deposited filter cake and the breaker fluid system. The RDF and breaker fluid formulation optimization was performed whilst keeping in mind the operational requirements and the well’s future injectivity The presented results show successful qualification of two independent fluid and breaker fluid systems where filter cake breakthrough is achieved within the desired time frame. The fluid systems in combination with the lower completion design and operational procedures ensure maximal reservoir exposure of the breaker fluid solution and enable rapid deterioration of the filter cake.

Emerging Techniques in Measuring Capillary Pressure and Permeability Using NMR and AI

2021 ◽  
Author(s):  
Ahmed Ghamdi ◽  
Abubakar Isah ◽  
Mahmoud Elsayed ◽  
Kareem Garadi ◽  
Abdulazeez Abdulraheem
Keyword(s):  
Capillary Pressure ◽  
Rock Properties ◽  
Full Potential ◽  
Data Set ◽  
Ongoing Research ◽  
Field Development ◽  
Conventional Methods ◽  
Capillary Pressures ◽  
Reservoir Description

Abstract Measurement of Special Core Analysis (SCAL) parameters is a costly and time-intensive process. Some of the disadvantages of the current techniques are that they are not performed in-situ, and can destroy the core plugs, e.g., mercury injection capillary pressure (MICP). The objective of this paper is to introduce and investigate the emerging techniques in measuring SCAL parameters using Nuclear Magnetic Resonance (NMR) and Artificial Intelligence (Al). The conventional methods for measuring SCAL parameters are well understood and are an industry standard. Yet, NMR and Al - which are revolutionizing the way petroleum engineers and scientists describe rock/fluid properties - have yet to be utilized to their full potential in reservoir description. In addition, integration of the two tools will open a greater opportunity in the field of reservoir description, where measurement of in-situ SCAL parameters could be achieved. This paper shows the results of NMR lab experiments and Al analytics for measuring capillary pressures and permeability. The data set was divided into 70% for training and 30% for validation. Artificial Neural Network (ANN) was used and the developed model compared well with the permeability and capillary pressure data measured from the conventional methods. Specifically, the model predicted permeability 10% error. Similarly, for the capillary pressures, the model was able to achieve an excellent match. This active research area of prediction of capillary pressure, permeability and other rock properties is a promising emerging technique that capitalizes on NMR/AI analytics. There is significant potential is being able to evaluate wettability in-situ. Core-plugs undergoing Amott-Harvey experiment with NMR measurements in the process can be used as a building block for an NMR/AI wettability determination technique. This potential aspect of NMR/AI analytics can have significant implications on field development and EOR projects The developed NMR-Al model is an excellent start to measure permeability and capillary pressure in-situ. This novel approach coupled with ongoing research for better handling of in-situ wettability measurement will provide the industry with enormous insight into the in-situ SCAL measurements which are currently considered as an elusive measurement with no robust logging technique to evaluate them in-situ.

An Integrated Approach Using Geomechanics and Advanced Rock Characterization Techniques to Optimize Reservoir Productivity and Stimulation Design

2014 ◽  
Author(s):  
M.. Nguyen ◽  
T.. Worku ◽  
W.P.. P. Mitchell ◽  
M.R.. R. Lakshmikantha ◽  
M.. Hegazy
Keyword(s):  
Rock Strength ◽  
Sampling Rate ◽  
Integrated Approach ◽  
Development Planning ◽  
Rock Properties ◽  
Rock Surface ◽  
Geomechanical Properties ◽  
Field Development ◽  
Well Completion ◽  
Rock Characterization

Abstract Accurate prediction of geomechanical rock properties is one of the main challenges to be overcome in E&P projects, in order to optimize well completion design and stimulation strategy. This is especially so in the early stages of a project, e.g the appraisal phase. In the recent years, Scratch Testing has become an emerging geomechanical characterization technique that is used to determine the mechanical properties of the rock. With this method, a groove of fixed depth (typically less than 1 mm) is scratched on the rock surface. The forces acting on the cutter are recorded at a high sampling rate (about 10 samples per millimeter), with high precision and resolution (about 1 Newton). This scratch test data is then used to characterize the length of heterogeneity of the rock, and to generate the geomechanical properties profile (rock strength, friction angle). Presently, such valuable information is only partially integrated with petrophysical and geological data. A series of Scratch tests are performed on different rock samples and types to create a continuous rock strength profile, which is then integrated with sedimentology, core analysis and wireline logs. This data assimilation led to the development of, a new technique to assist in the extrapolation of rock strength in un-cored intervals/wells. In this paper, the developed workflow will be further elaborated, along with its results and applications to support the design of a fit for purpose well completion and stimulation strategy, which is a key component in the field development planning phase of an E&P project.

scholarly journals Incremental and acceleration production estimation and their effect on optimization of well infill locations in tight gas reservoirs

2021 ◽  
Author(s):  
Atheer Dheyauldeen ◽  
Omar Al-Fatlawi ◽  
Md Mofazzal Hossain
Keyword(s):  
Transient Flow ◽  
Development Planning ◽  
Main Role ◽  
Gas Reservoirs ◽  
Type Curves ◽  
Field Development ◽  
Drilling Performance ◽  
Well Location ◽  
Infill Drilling ◽  
Tight Formations

AbstractThe main role of infill drilling is either adding incremental reserves to the already existing one by intersecting newly undrained (virgin) regions or accelerating the production from currently depleted areas. Accelerating reserves from increasing drainage in tight formations can be beneficial considering the time value of money and the cost of additional wells. However, the maximum benefit can be realized when infill wells produce mostly incremental recoveries (recoveries from virgin formations). Therefore, the prediction of incremental and accelerated recovery is crucial in field development planning as it helps in the optimization of infill wells with the assurance of long-term economic sustainability of the project. Several approaches are presented in literatures to determine incremental and acceleration recovery and areas for infill drilling. However, the majority of these methods require huge and expensive data; and very time-consuming simulation studies. In this study, two qualitative techniques are proposed for the estimation of incremental and accelerated recovery based upon readily available production data. In the first technique, acceleration and incremental recovery, and thus infill drilling, are predicted from the trend of the cumulative production (Gp) versus square root time function. This approach is more applicable for tight formations considering the long period of transient linear flow. The second technique is based on multi-well Blasingame type curves analysis. This technique appears to best be applied when the production of parent wells reaches the boundary dominated flow (BDF) region before the production start of the successive infill wells. These techniques are important in field development planning as the flow regimes in tight formations change gradually from transient flow (early times) to BDF (late times) as the production continues. Despite different approaches/methods, the field case studies demonstrate that the accurate framework for strategic well planning including prediction of optimum well location is very critical, especially for the realization of the commercial benefit (i.e., increasing and accelerating of reserve or assets) from infilled drilling campaign. Also, the proposed framework and findings of this study provide new insight into infilled drilling campaigns including the importance of better evaluation of infill drilling performance in tight formations, which eventually assist on informed decisions process regarding future development plans.

Machine Learning in Computer Vision Software for Geomechanics Modeling

2021 ◽  
Author(s):  
Abdelwahab Noufal ◽  
Jaijith Sreekantan ◽  
Rachid Belmeskine ◽  
Mohamed Amri ◽  
Abed Benaichouche
Keyword(s):  
Machine Learning ◽  
Data Gathering ◽  
In Situ Stress ◽  
Effective Field ◽  
Rock Properties ◽  
Earth Model ◽  
Transient Effects ◽  
Rock Interaction ◽  
Wellbore Instability ◽  
Detail Design

Abstract AI-GEM (Artificial Intelligence of Geomechanics Earth Modelling) tool aims to detect the geomechanical features, especially the elastic parameters and stresses. Characterizing the wellbore instability issues is one of the factors increases cost of drilling and creating an AI-based tool will enhance and present a real-time solution for wellbore instability. These features are usually interpreted manually, depending on the experience and usually impacted by inconsistencies due to biased or unexperienced interpreters. Therefore, there is a need for a robust automatic or semiautomatic approach to reduce time, manual efficiency and consistency. The range of Geomechanics issues is wide and interfaces with many other upstream disciplines (e.g., Petrophysics, Geophysics, Production Geology, Drilling and Reservoir Engineering). Safe and effective field operation is built on the understanding and implementation of the subsurface in-situ stress state throughout the life of the field; the quantification of key subsurface uncertainties through well thought-out data gathering and characterization programs. The integration with appropriate Geomechanics modelling and the field surveillance /monitoring strategy. There are two major aspects that must be addressed during the design phase of any Geomechanics project. The first and most important is developing a realistic estimate of the expected mechanical behaviour of the rocks and its potential response as a result of drilling. The second is to design an economic, safe well and support method for the determined rocks behaviour. The design process begins with the feasibility study followed by preliminary design, the detail design, tender design and throughout the construction. The design is constantly updated during each phase as more information becomes available and this requires the involvement of Geologists, Engineers and Subject Matter Expert throughout the phases of a project. A central concern for all geomechanical designs is the well-rock interaction, which is not only includes the final state but also the transient effects of the well processes as well as time and stress of the dependent rock properties. The end-to-end workflow to achieve the mechanical earth model is automated, guided and orchestrated with the help of machine learning framework such as recommendation engine for offset well data, prediction of well logs, and optimization for all calibration with existing test results, enabling end users to run sensitivity and scenario analysis so on and so forth.

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