Complex Stimulation Approach to Low-Temperature Carbonate Formation Revitalizes Bahrain Brownfield

2021 ◽  
Author(s):  
Ahmed AlJanahi ◽  
Sayed Abdelrady ◽  
Hassan AlMannai ◽  
Feras AlTawash ◽  
Eyad Ali ◽  
...  
Keyword(s):  
Low Temperature ◽  
Oil Recovery ◽  
Mesh Size ◽  
Lessons Learned ◽  
Laboratory Research ◽  
Fracture Width ◽  
Field Development ◽  
Fracture Length ◽  
Carbonate Formation ◽  
Formation Pore Pressure

Abstract Carbonate formations often require stimulation treatments to be developed economically. Sometimes, proppant fracturing yields better results than acid stimulation. Carbonates are seldom stimulated with large-mesh-size proppants due to admittance issues caused by fissures and high Young’s modulus and narrow fracture width. The Magwa formation of Bahrain’s Awali brownfield is a rare case in which large treatments using 12/20-mesh proppant were successful after the more than 50 years of field development. To achieve success, a complex approach was required during preparation and execution of the hydraulic fracturing campaign. During the first phase, the main challenges that restricted achieving full production potential in previous stimulation attempts (both acid and proppant fracturing) were identified. Fines migration and shale instability were addressed during advanced core testing. Tests for embedment were conducted, and a full suite of logs was obtained to improve geomechanical modeling. In addition, a target was set to maximize fracture propped length to address the need for maximum reservoir contact in the tight Magwa reservoir and to maximize fracture width and conductivity. Sufficient fracture width in the shallow oil formation was required to withstand embedment. Sufficient conductivity was required to clean out the fracture under low-temperature conditions (124°F) and to minimize drawdown along the fracture considering the relatively low energy of the formation (pore pressure less than 1,000 psi). Understanding the fracture dimensions was critical to optimize the design. Independent measurement using high-resolution temperature logging and advanced sonic anisotropy measurements after fracturing helped to quantify fracture height. As a result of the applied comprehensive workflow, 18 wells were successfully stimulated, including three horizontal wellbores with multistage fracturing - achieving effective fracture half-lengths of 450-to 500-ft. Oil production from the wells exceeded expectations and more than doubled the results of all the previous attempts. Production decline rates were also less pronounced due to achieved fracture length and the ability to produce more reservoir compartments. The increase in oil recovery is due to the more uniform drainage systems enabled by the conductive fractures. The application of new and advanced techniques taken from several disciplines enabled successful propped fracture stimulation of a fractured carbonate formation. Extensive laboratory research and independent geometry measurements yielded significant fracture optimization and resulted in a step-change in well productivity. The techniques and lessons learned will be of benefit to engineers dealing with shallow carbonate reservoirs around the world.

Case History: Coring in ERD Well with Collision Risk Challenge and Optimization of Coring Parameters Based on Previous Coring Jobs in Carbonate Formation Alleviated Core Recovery

2021 ◽  
Author(s):  
Rahul Kamble ◽  
Youssef Ali Kassem ◽  
Kshudiram Indulkar ◽  
Kieran Price ◽  
Majid Mohammed A. ◽  
...  
Keyword(s):  
United Arab Emirates ◽  
Lessons Learned ◽  
Low Flow ◽  
High Angle ◽  
Collision Risk ◽  
Pilot Hole ◽  
Field Development ◽  
Core Recovery ◽  
Carbonate Formation ◽  
Carbonate Formations

Abstract Coring during the development phase of an oil and gas field is very costly; however, the subsurface insights are indispensable for a Field Development Team to study reservoir characterization and well placement strategy in Carbonate formations (Dolomite and limestone with Anhydrite layers). The objective of this case study is to capture the successful coring operation in high angle ERD wells, drilled from the fixed well location on a well pad of an artificial island located offshore in the United Arab Emirates. The well was planned and drilled at the midpoint of the development drilling campaign, which presented a major challenge of wellbore collision risk whilst coring in an already congested area. The final agreed pilot hole profile was designed to pass through two adjacent oil producer wells separated by a geological barrier, however, the actual separation ratio was < 1.6 (acceptable SF to drill the well safely), which could have compromised the planned core interval against the Field Development Team's requirement. To mitigate the collision risks with offset wells during the coring operation, a low flow rate MWD tool was incorporated in the coring BHA to monitor the well path while cutting the core. After taking surveys, IFR and MSA corrections were applied to MWD surveys, which demonstrated an acceptable increase in well separation factor as per company Anti-Collision Risk Policy to continue coring operations without shutting down adjacent wells. A total of 3 runs incorporating the MWD tool in the coring BHA were performed out of a total of 16 runs. The maximum inclination through the coring interval was 73° with medium well departure criteria. The main objective of the pilot hole was data gathering, which included a full suite of open hole logging, seismic and core cut across the target reservoir. A total of 1295 ft of core was recovered in a high angle well across the carbonate formation's different layers, with an average of 99% recovery in each run. These carbonate formations contain between 2-4% H2S and exhibit some fractured layers of rock. To limit and validate the high cost of coring operations in addition to core quality in the development phase, it was necessary to avoid early core jamming in the dolomite, limestone and anhydrite layers, based on previous coring runs in the field. Core jamming leads to early termination of the coring run and results in the loss of a valuable source of information from the cut core column in the barrel. Furthermore, it would have a major impact on coring KPIs, consequently compromising coring and well objectives. Premature core jamming and less-than-planned core recovery from previous cored wells challenged and a motivated the team to review complete field data and lessons learned from cored offset wells. Several coring systems were evaluated and finally, one coring system was accepted based on core quality as being the primary KPI. These lessons learned were used for optimizing certain coring tools technical improvements and procedures, such as core barrel, core head, core handling and surface core processing in addition to the design of drilling fluids and well path. The selection of a 4" core barrel and the improved core head design with optimized blade profile and hold on sharp polished cutters with optimized hydraulic efficiency, in addition to the close monitoring of coring parameters, played a significant role in improving core cutting in fractured carbonate formation layers. This optimization helped the team to successfully complete the 1st high angle coring operation offshore in the United Arab Emirates. This case study shares the value of offset wells data for coring jobs to reduce the risk of core jamming, optimize core recovery and reduce wellbore collision risks. It also details BHA design decisions(4"core barrel, core head, low flow rate MWD tool and appropriate coring parameters), all of which led to a new record of cutting 1295 ft core in a carbonate formation with almost 100% recovery on surface.

scholarly journals Practical CO2—WAG Field Operational Designs Using Hybrid Numerical-Machine-Learning Approaches

Energies ◽  
2021 ◽  
Vol 14 (4) ◽  
pp. 1055
Author(s):  
Qian Sun ◽  
William Ampomah ◽  
Junyu You ◽  
Martha Cather ◽  
Robert Balch
Keyword(s):  
Machine Learning ◽  
Oil Recovery ◽  
History Matching ◽  
Optimization Problems ◽  
Learning Technologies ◽  
Petroleum Engineering ◽  
Support Vector ◽  
Learning Approaches ◽  
Field Development ◽  
Proxy Models

Machine-learning technologies have exhibited robust competences in solving many petroleum engineering problems. The accurate predictivity and fast computational speed enable a large volume of time-consuming engineering processes such as history-matching and field development optimization. The Southwest Regional Partnership on Carbon Sequestration (SWP) project desires rigorous history-matching and multi-objective optimization processes, which fits the superiorities of the machine-learning approaches. Although the machine-learning proxy models are trained and validated before imposing to solve practical problems, the error margin would essentially introduce uncertainties to the results. In this paper, a hybrid numerical machine-learning workflow solving various optimization problems is presented. By coupling the expert machine-learning proxies with a global optimizer, the workflow successfully solves the history-matching and CO2 water alternative gas (WAG) design problem with low computational overheads. The history-matching work considers the heterogeneities of multiphase relative characteristics, and the CO2-WAG injection design takes multiple techno-economic objective functions into accounts. This work trained an expert response surface, a support vector machine, and a multi-layer neural network as proxy models to effectively learn the high-dimensional nonlinear data structure. The proposed workflow suggests revisiting the high-fidelity numerical simulator for validation purposes. The experience gained from this work would provide valuable guiding insights to similar CO2 enhanced oil recovery (EOR) projects.

Optimization Applied to Buzios Flexible Riser Systems and Subsea Layout

2021 ◽  
Author(s):  
Vinicius Gasparetto ◽  
Thierry Hernalsteens ◽  
Joao Francisco Fleck Heck Britto ◽  
Joab Flavio Araujo Leao ◽  
Thiago Duarte Fonseca Dos Santos ◽  
...  
Keyword(s):  
Deep Water ◽  
Technology Use ◽  
Capital Expenditure ◽  
Lessons Learned ◽  
Internal Diameter ◽  
Flexible Riser ◽  
Flexible Pipe ◽  
Injection Wells ◽  
Gas Field ◽  
Field Development

Abstract Buzios is a super-giant ultra-deep-water pre-salt oil and gas field located in the Santos Basin off Brazil's Southeastern coast. There are four production systems already installed in the field. Designed to use flexible pipes to tie back the production and injection wells to the FPSOs (Floating Production Storage and Offloading), these systems have taken advantage from several lessons learned in the previous projects installed by Petrobras in Santos Basin pre-salt areas since 2010. This knowledge, combined with advances in flexible pipe technology, use of long-term contracts and early engagement with suppliers, made it possible to optimize the field development, minimizing the risks and reducing the capital expenditure (CAPEX) initially planned. This paper presents the first four Buzios subsea system developments, highlighting some of the technological achievements applied in the field, as the first wide application of 8" Internal Diameter (ID) flexible production pipes for ultra-deep water, leading to faster ramp-ups and higher production flowrates. It describes how the supply chain strategy provided flexibility to cover the remaining project uncertainties, and reports the optimizations carried out in flexible riser systems and subsea layouts. The flexible risers, usually installed in lazy wave configurations at such water depths, were optimized reducing the total buoyancy necessary. For water injection and service lines, the buoyancy modules were completely removed, and thus the lines were installed in a free-hanging configuration. Riser configuration optimizations promoted a drop of around 25% on total riser CAPEX and allowed the riser anchor position to be placed closer to the floating production unit, promoting opportunities for reducing the subsea tieback lengths. Standardization of pipe specifications and the riser configurations allowed the projects to exchange the lines, increasing flexibility and avoiding riser interference in a scenario with multiple suppliers. Furthermore, Buzios was the first ultra-deep-water project to install a flexible line, riser, and flowline, with fully Controlled Annulus Solution (CAS). This system, developed by TechnipFMC, allows pipe integrity management from the topside, which reduces subsea inspections. As an outcome of the technological improvements and the optimizations applied to the Buzios subsea system, a vast reduction in subsea CAPEX it was achieved, with a swift production ramp-up.

Multistage Openhole Completion Using Integrated Dynamic Diversion Frac Technique in Highly Depleted Well: First Successful Application in West Kuwait Field

2021 ◽  
Author(s):  
Abdullah Abu-Eida ◽  
Salem Al-Sabea ◽  
Milan Patra ◽  
Bader Akbar ◽  
Kutbuddin Bhatia ◽  
...  
Keyword(s):  
Best Practice ◽  
Treatment Options ◽  
High Energy ◽  
Lessons Learned ◽  
High Potential ◽  
Fracture Plane ◽  
Fluid Loss ◽  
Field Development ◽  
Two Fluids

Abstract The Minagish field in West Kuwait is a high potential field which poses several challenges in terms of hydrocarbon flow assurance through highly depleted tight carbonate intervals with uneven reservoir quality and curtailed mobility. These conditions have shifted the field development from vertical to horizontal wellbore completions. Achieving complete wellbore coverage is a challenge for any frac treatment performed in a long openhole lateral with disparities in reservoir characteristics. The fluid will flow into the path of least resistance leaving large portions of the formation untreated. As a result, economic fracturing treatment options dwindle significantly, thus reservoir stimulation results are not always optimum. A multistage fracturing technique using Integrated Dynamic Diversion (IDD) has been performed first time in West Kuwait field well. The process uses active fluid energy to divert flow into a specific fracture point in the lateral, which can initiate and precisely place a fracture. The process uses two self-directed fluid streams: one inside the pipe and one in the annulus. The process mixes the two fluids downhole with high energy to form a consistent controllable mixture. The technique includes pinpoint fluid jetting at the point of interest, followed by in-situ HCL based crosslinked systems employed for improving individual stage targets. The IDD diversion shifts the fracture to unstimulated areas to create complex fractures which increases reservoir contact volume and improved overall conductivity in the lateral. The kinetic and chemical diversion of the IDD methodology is highly critical to control fluid loss in depleted intervals and results in enhanced stimulation. Pumping a frac treatment in openhole without control would tend to initiate a longitudinal fracture along the wellbore and may restrict productivity. By using specialized completion tools with nozzles at the end of the treating string, a new pinpoint process has been employed to initiate a transverse fracture plane in IDD applications. Proper candidate selection and fluid combination with in-situ crosslink acid effectively plug the fracture generated previously and generate pressure high enough to initiate another fracture for further ramification. By combining these processes into one continuous operation, the use of wireline/coiled tubing for jetting, plug setting and milling is eliminated, making the new multistage completion technology economical for these depleted wells. The application of the IDD methodology is a fit-for-purpose solution to address the unique challenges of openhole operations, formation technical difficulties, high-stakes economics, and untapped high potential from intermittent reservoirs. The paper will present post-operation results of this completion from all fractured zones along the lateral and will describe the lessons learned in implementation of this methodology which can be considered as best practice for application in similar challenges in other fields.

Greater Plutonio Riser Tower Installation: Studies and Lessons Learnt

2009 ◽  
Author(s):  
Charles-Alexandre Zimmermann ◽  
Guilhem Layrisse ◽  
Daniel de la Cruz ◽  
Jeremy Gordonnat
Keyword(s):  
Water Depth ◽  
Bending Moment ◽  
Lessons Learned ◽  
Field Development ◽  
System A ◽  
Analysis Methodology ◽  
Lessons Learnt ◽  
Future Improvement ◽  
Tower System

The BP operated Greater Plutonio field development offshore Angola comprises a spread-moored FPSO in 1,300 m water depth, serving as a hub processing the fluids produced from or injected into the subsea wells. The selected riser system is a Hybrid Riser Tower comprising 11 risers bundled around a central structural tubular (Core Pipe), tensioned by a steel Buoyancy Tank at its top and maintained by an anchor base at its bottom. The Riser Tower is fabricated onshore and then towed to the field for final installation in deepwater near the FPSO. Once the Riser Tower installation is completed the risers are connected to the FPSO by means of flexible jumpers and to the flowlines by means of rigid spools. All fabrication and installation work has been performed by Acergy. This paper presents the studies performed to cover all the steps of the installation phase: build-up of the Orcaflex model, miscellaneous studies to determine model and analyses parameters, towing analysis, upending analysis, Buoyancy Tank ballasting and deballasting analyses, and contingency analyses. This paper is mainly focused on the Riser Tower installation but also covers the installation of the Riser Tower anchor and of the flexible jumpers in order to give a complete overview of the operations related to the Riser Tower system. A comparison between computed data and data measured during operations is also presented to support the overall installation analysis methodology. Lessons learned are provided for future improvement of Riser Tower installation covering main challenges such as Riser Tower modeling, weight/buoyancy repartition along the Riser Tower, Buoyancy Tank ballasting adjustment in Lobito bay, fatigue issues during surface and subsurface tow, bending moment issues during upending, etc.

Azurite Field Development: Lessons Learned From Industry

2010 ◽  
Author(s):  
Harry J. Howard ◽  
Kenneth Christopher Hampshire ◽  
Jeffrey Allen Moore ◽  
Charles White ◽  
Kenneth J. Bayne
Keyword(s):  
Lessons Learned ◽  
Field Development

scholarly journals Integrated Halo Model And Hydrodynamic Simulation For Optimization Oil Production In Crystalline Fractured Reservoirs

2021 ◽  
Author(s):  
Hung Vo Thanh ◽  
Kang-Kun Lee
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Fractured Reservoirs ◽  
Petroleum Industry ◽  
Oil Production ◽  
Modelling And Simulation ◽  
Development Plan ◽  
Sweep Efficiency ◽  
Field Development ◽  
The World

Abstract Basement formation is known as the unique reservoir in the world. The fractured basement reservoir was contributed a large amount of oil and gas for Vietnam petroleum industry. However, the geological modelling and optimization of oil production is still a challenge for fractured basement reservoirs. Thus, this study aims to introduce the efficient workflow construction reservoir models for proposing the field development plan in a fractured crystalline reservoir. First, the Halo method was adapted for building the petrophysical model. Then, Drill stem history matching is conducted for adjusting the simulation results and pressure measurement. Next, the history-matched models are used to conduct the simulation scenarios to predict future reservoir performance. The possible potential design has four producers and three injectors in the fracture reservoir system. The field prediction results indicate that this scenario increases approximately 8 % oil recovery factor compared to the natural depletion production. This finding suggests that a suitable field development plan is necessary to improve sweep efficiency in the fractured oil formation. The critical contribution of this research is the proposed modelling and simulation with less data for the field development plan in fractured crystalline reservoir. This research's modelling and simulation findings provide a new solution for optimizing oil production that can be applied in Vietnam and other reservoirs in the world.

Feasibility Study on the Implementation of CO2-EOR Coupled with Sequestration in Trinidad via Reservoir Simulation

2014 ◽  
Author(s):  
J.. Narinesingh ◽  
D. V. Boodlal ◽  
D.. Alexander
Keyword(s):  
Primary Production ◽  
Oil Recovery ◽  
Net Present Value ◽  
Fluid Model ◽  
Gas Production ◽  
Economic Feasibility ◽  
Utilization Rate ◽  
Optimum Number ◽  
Field Development ◽  
Co2 Eor

Abstract The paper seeks to assess the technical and economic feasibility of implementing carbon dioxide enhanced oil recovery (CO2 EOR) in Trinidad and Tobago from flue gas production whilst mitigating the effect of greenhouse gases via CO2 sequestration. An existing power plant in Trinidad was selected as the CO2 source. As such, actual CO2 volumes and properties were found and used in this analysis. However, a hypothetical field was chosen as the appropriate sink, which can be analogous to a field in onshore Trinidad. A detailed reservoir model was built using the compositional fluid model CMG-GEM. Various scenarios were simulated to determine the optimum number of producers for primary production and the best location of the injectors for CO2 EOR. The optimum number of producers for the reservoir during primary production was found. In addition, the most favorable location of the injector to avoid early breakthrough and increase oil recovery was also determined. Many key parameters were reported from this investigation. These included OIIP, forecasted production and primary recovery. After primary production, CO2 EOR was then implemented with the use of the reservoir and fluid models and the additional recovery is reported. Other Key CO2-EOR parameters such as CO2 utilization rate and total sequestered CO2 were also quantified. Though a hypothetical reservoir was used, all associated data were defined and once an actual reservoir is known, the same technically rigid methodology can be applied. The OIIP was found to be 6.74 MMSTB for the selected reservoir. Based on an economic net present value (NPV) assessment, the optimum number of production wells for field development was found to be 3. At the end of primary production from these three wells (with 2.375 in. tubing), a total of 1.83 MMSTB were produced. This corresponded to a primary recovery factor of 27.2% over 4 years and 2 months. For CO2 EOR coupled with sequestration, these three wells were manipulated and used as 1 injector and 2 producers. CO2 EOR led to another 1.07 MMSTB of recovery for a total of 2.9 MMSTB (43.04% Recovery) for the ten year life of the project. A total of 5427 MMSCF (287 000 tons) of CO2 was sequestered in the reservoir (40.39% Storage) at an injection pressure of 1400 psi.

Recommendations for the multilateral wells design selection in various geological conditions based on lessons learned

2021 ◽  
pp. 159-167
Author(s):  
A. A. Zernin ◽  
E. S. Ziuzev ◽  
A. S. Sergeev ◽  
R. M. Khismatullin ◽  
M. A. Starikov
Keyword(s):  
Lessons Learned ◽  
Energy Conditions ◽  
Reservoir Properties ◽  
Field Development ◽  
Well Design ◽  
Well Efficiency ◽  
Geological Conditions ◽  
Efficiency Estimation ◽  
Design Selection ◽  
First Time

The authors of the article have summarized the experience of multilateral well application, performed an efficiency analysis of multilateral wells vs horizontal wells in Rosneft Oil Company's fields with various subsurface architecture. The algorithm for multilateral well efficiency estimation, compared to other type of well completions, was developed. This algorithm is based on the selection of areas for well locations with similar reservoir properties, reservoir energy conditions, and reservoir development conditions to evaluate production startup parameters, decline rates, cumulative parameters for the areas of over 6 month production. A matrix of multilateral well applicability in various geological conditions was generated, and recommendations for preferable well design were made. This type of analysis was conducted for the first time due to collection of sufficient statistical data, because of a multiple increase in the amount of drilling complex wells in the recent years. The obtained results provide an opportunity to design an efficient field development system for new assets, perform an adjustment of brownfields development systems, select multilateral well design for certain geological conditions based on lessons learned.

Embarking on a New Philosophy: Sand Control Design and Exclusion Method for a Field in Peninsular Malaysia, Best Practices and Lessons Learned for Future Development

2021 ◽  
Author(s):  
Siti Nur Mahirah M Zain ◽  
Nur Hidayah M Zamani ◽  
Sunanda Magna Bela ◽  
Jagaan AL Selladurai ◽  
Saharul Hashim ◽  
...  
Keyword(s):  
Best Practices ◽  
Treatment Method ◽  
Peninsular Malaysia ◽  
Lessons Learned ◽  
Dry Coating ◽  
Carrier Fluid ◽  
Field Development ◽  
Sand Control ◽  
Close Proximity ◽  
Sand Accumulation

Abstract Field D is a massive oil-producing field, which consists of more than 15 blocks that have been developed since 1996. All types of completion methods, from openhole stand-alone screens and cased-hole circulating packs to frac packs, have been applied to help maximize field productivity while keeping sand issues to an acceptable level. However, some wells have begun to encounter sand issues, causing a drop in productivity and in some cases become shut-in because of sand accumulation in the tubing. Small fines (<40 micron) are particularly prominent in the produced sand based on samples collected. A field development revisiting campaign was launched to target new drainage points and recover attic oil using existing slots to sidetrack to the targeted zone and install a new downhole sand control completion. The preferred treatment method is an extension pack (EP) after considering reservoir characteristics, namely close proximity to a coal layer, low permeability, and small fines production, among others. These challenges were addressed by combining the oriented perforation design and optimal sand control completion system using a single-trip multizone system, enhanced single-trip multizone system, and a stack pack with a properly designed proppant pumping strategy using xanthan carrier fluid, a fines-control acid system, and 20/40-mesh ceramic proppant with a 10-gauge wire-wrapped screen. Numerous sand control software simulations were performed to achieve tip screenout (TSO) and a sufficient pack factor while addressing all of the wellbore conditions. For the first time in this field, conductivity enhancer material was applied by dry coating it to proppant on-the-fly with the goal of controlling fines migration through the proppant pack, thus increasing porosity and leading to long-term conductivity. The process design, execution, minifrac analysis, and post-job matching for the frac pack treatment are discussed, which lead to the wells producing sand-free at higher than expected reserves and flow rates. Best practices and lessons learned from this campaign can be further used for new upcoming campaigns.

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