bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pinpoint Fracture Acidizing Technology in Tight Carbonate Formation: Improved Recovery, Tuba Reservoir, North Kuwait
Authors: Ranjan Priya , Al-Qenae Amna , El-Aziz Sabry Abd , Al-Hashash Awrad , Al-Ajmi Hadi , Mofti Mohamed , Boueshi Alaeldin , Eid Walid , Sadeddin Salma , Allam Ahmed 
Published: October 2018

AbstractThe Tuba carbonate reservoir in the Sabriyah field, North Kuwait was deposited above the Wara shale and overlaid by the Ahmadi shale. It is divided into three stratigraphic units: upper, middle, and lower. This formation was considered to have limited opportunity for production enhancement. However, improved reservoir characterization along with developed pinpoint fracture acidizing technologies have provided new opportunities to improve recovery and increase pay zone productivity.Pinpoint fracture acidizing technology, using drillpipe with a bottomhole pinpoint tool assembly, has helped to effectively stimulate pay intervals individually using acid fracturing treatments. This resulted in achieving multiple stimulation treatments in a single trip, where each treatment stage was tailored for the specific interval being treated. Moreover, this pinpoint technique increased the number of treated stages per well compared to conventional multistage fracture acidizing, which led to greater efficiency and greater production.This technology has been successfully used for multiple zones in complex reservoirs to improve production and reservoir recovery. It provided an effective method to help boost production and injection from tight zones in openhole horizontal completions and completions where zonal isolation could be compromised. This treatment process helped optimize hydrajetting and acid fracturing technologies along with treatment design for individually placed fractures by using the dynamic fluid movement to divert fluid flow into a specific treatment point in the formation. This service required a different approach to treatment design by controlling and evaluating two primary fluid injection paths, which necessitates two separate pumping systems. However, a proper well candidate is important to the success of any stimulation treatment.This paper discusses methodology and treatments applied on a recent well in the Tuba carbonate reservoir in a horizontal openhole completion. The technical approach taken during the design of the treatments is presented in detail, as well as the operational challenges encountered during the multistage fracture acidizing treatments. This stimulation technique was implemented successfully to perform a seven-stage acid treatment in a single lateral. The overall success of this project proves that there is a technical alternative to the traditional fracture acidizing methodology for wells of this type.
Best Practices for Frac Pack on High Permeability/Unconsolidated Reservoirs: Experience from Offshore Brazil Operations
Authors: Colbert F. C. , Garcia F. M. , Costa A.. , Gachet R.. , Mattos H.. , Junior A.. 
Published: October 2018

Abstract
The Campos basin is a sedimentary basin located in offshore Brazil, between the north coast of Rio de Janeiro State and the south coast of Espírito Santo State. Most of the reservoirs on the post-salt layers are high permeability sandstones (2,000 mD up to 6,000 mD), containing low API gravity oil. In addition to the high permeability, these sandstones are unconsolidated, which demands a sand control method to make oil and gas production feasible.
In the original field development, conventional gravel packs were used as a sand control method, but post job analysis indicated high skins after the treatment, even using the best completion and placement techniques. This study offers an insight of the best practices and lessons learned from the design and pumping of more than 130 packs over more than two decades in offshore Brazil (water depths from 33 up to ~1800m). The main aspects discussed include frac pack design considerations, typical procedures, fracturing equipment overview, pressure management strategies and the need for a high quality fluid system and proppant.
Frac pack completions were introduced in the end of the 90's and became a usual completion method for the Campos basin. Post job analysis indicates that this type of treatment provided better results than the convention gravel pack including lower skins after treatment. Due to the challenging reservoir characteristics, the strategy for frac pack design was to create a highly conductivity fracture, aiming to reduce the skin as much as possible, by using aggressive Tip Screen Out (TSO) designs.
The TSO provides a short but wide and very conductive fracture, which is essential for high permeability wells. This technique bypasses the near wellbore damage caused by the previous drilling and completion practices such as drilling fluids, perforating debris and completion fluids invasion. This method can improve the effectiveness of the production, enhancing the oil recovery.
Correlations Between the Economic Value Added and Reservoir and Frac Properties in the Dutch Hydraulic Fracture Portfolio
Authors: Huijskes T. D. , Godderij R. R. , Leo T.. 
Published: October 2018

Abstract
Since the first frac in 1954, around 250 of the 3000 exploration and production wells in the Netherlands have been hydraulically fractured. This study focusses on about 50 of the more recent fracs, of which sufficient production data, reservoir information and hydraulic fracture properties could be obtained for economic and data analysis.
For each well, the production history has been analyzed with a commercial rate transient analysis software package. About half of the wells have a pre-frac production history while the other half have been hydraulically fractured immediately after drilling. For wells with pre- and post-frac production data two history matched analytical models were made. Those models were subsequently used to create two production forecasts, to determine the incremental production profile and to calculate the economic value added by each frac. For wells without pre-frac production data the history matched post-frac model was used two create two production forecasts, one with and one without a hydraulic fracture in place.
The calculated economic values have been combined with reservoir properties (permeability, GIIP, stratigraphy, etc.) and frac data (proppant type, amount of fluid used, amount of proppant pumped, etc.), to form a dataset which was analyzed using a commercial data analysis tool to investigate perceived correlations.
The results show that practically all analyzed fracs resulted in a production improvement, and most of the fracs resulted in positive economic value added. However, some resulted in an economic grey area (below EUR 5 million incremental discounted cash flow), and one frac even resulted in a negative value.
Many reasons can be given for the distinction between economic and uneconomic projects. This paper shows that although multiple attributes influence the calculated economic value, some generic observations can be made. There is apparently no correlation between PI improvement, skin or kh and economic value. Remaining GIP is definitely important for economic value, but no generic correlation for reservoir pressure can be made. It was shown that wells often see more connected GIIP after fraccing. The results show that fracs in reservoirs with 80% depletion can still result in very economically beneficial projects, especially if the fracs increase the connected GIIP. Frac properties might very well be important for the determination of the economic value of fractures. However, no clear correlation between economic value and frac half length or proppant size could be found. On the other hand, the results show that larger amounts of (any) proppant pumped seem to lead to higher economic value. Last but not least, a relation between PI improvement and pre-frac skin was found.
The study presented is the first portfolio analysis of fracced conventional gas wells in The Netherlands. Input and methods have been checked and results have been shared with several experts outside our organization.
Guidelines for Optimizing Acid Fracture Design Using an Integrated Acid Fracture and Productivity Model
Authors: Aljawad Murtada Saleh , Schwalbert Mateus Palharini , Zhu Ding , Hill Alfred Daniel 
Published: October 2018

AbstractThe performance of acid fractured wells depends on the conductivity distribution along the acid penetration length, which is a function of reservoir properties, treatment design and execution. The previously published models for fractured well performance assume constant fracture conductivity, which cannot be achieved in acid fracturing operations. This work proposes a design optimization method where acid fracture and reservoir models are integrated. Fracture conductivity distribution along the fracture surface is considered in the optimization process.In the new integrated model, the acid transport and reaction is joined to the fracture propagation and heat transfer models. The dissolution patterns along fracture surfaces are generated, and that is converted to a conductivity distribution. To predict the fractured well productivity, the reservoir model is built using the input reservoir properties as well as the calculated acid fracture geometry and conductivity distribution. The acid fracturing parameters that lead to the optimum fracture productivity are determined with this integrated model.This method shows that there is an optimum productivity that can be obtained for a given acid treatment volume and reservoir properties. Design parameters such as flow rate, viscosity, acid concentration, acid treatment volume, pad, and overflush volumes, can be selected to achieve the optimum well performance. Reservoir permeability has an important impact on how acid fracture jobs should be designed. At low reservoir permeability, a more evenly distributed conductivity and long acid penetration length is preferred. This can be accomplished by injecting a retarded acid system at moderate to high flow rate. However, excessive fracture height growth should be prevented by carefully designing the injection rate and viscosity. For high permeability reservoirs, higher conductivity along a shorter acid penetration length is targeted. This can be obtained by selecting a more reactive acid system such as straight acid and injecting at moderate rates, or lowering injection rate of retarded acids. Minimum amount of pad should be used in this case. Still, the flow rate should be high enough to keep the fracture open during acid injection. This paper also shows how acid concentration and fluid stages can be designed to optimize productivity, and presents a procedure for selecting the acid treatment volume.A theoretical model which integrates acid fracturing and reservoir flow is used to implement the guidelines on optimizing acid fracture design parameters. This paper provides a scientific approach to determine acid treatment volume that yields the optimal outcomes of acid fracturing.
Polyelectrolyte Complex Stabilized CO2 Foam Systems for Improved Fracture Conductivity and Reduced Fluid Loss
Authors: Anandan Rudhra , Barati Reza , Johnson Stephen 
Published: October 2018

AbstractThe objective of this work was to develop a supercritical CO2 foam with a liquid phase composed of a polyelectrolyte complex nanoparticle system interacting with a viscoelastic surfactant solution. This is intended to be used as a fracturing fluid to reduce fluid loss and increase post-fracture clean-up efficiency for improved productivity in unconventional reservoirs. In a previous study, we optimized the polycation/polyanion ratio and polyelectrolyte pH using zeta potential and phase-angle light scattering. Rheological and foam stability tests were used to further optimize surfactant/polyelectrolyte ratio. In this work, dynamic fluid loss tests were performed on supercritical CO2 foam generated using the optimized ratio of surfactant/PECNP to investigate the effect of PECNP addition to the surfactant solution on the fluid loss. The same foam systems were used to investigate post fracture clean up using sand pack tests. Interfacial tension was measured on both air-(surfactant/PECNP) and supercritical CO2-(surfactant/PECNP) systems to understand the effect of PECNP on IFT. Fluid loss to the formation during hydraulic fracturing causes water blockage, formation damage and capillary pressure shift, lowering the conductivity of the reservoir, and impeding the flow of oil and gas. Supercritical CO2 foam generated by surfactant solution exhibited low fluid loss, thus lower values of fluid loss coefficient compared to unfoamed surfactant systems. However, addition of polyelectrolyte complex nanoparticles further reduced the total fluid loss and fluid loss coefficient. Foam fracturing fluids break in the presence of crude oil because the oil penetrates the foam lamellae causing drainage and lamellar rupture; this results in effective post fracture clean up using supercritical CO2 foam as fracturing fluid. Foam systems generated by surfactant showed promising clean up results, and the addition of PECNP further increased clean up efficiency. From IFT test results we concluded that the addition of PECNP decreased interfacial tension of both air-(surfactant/PECNP) and supercritical CO2-(surfactant/PECNP) systems. The addition of optimized polyelectrolyte complex nanoparticles to surfactant in a supercritical CO2 foam fracturing fluid can reduce interfacial tension and fluid loss, which will reduce formation damage, resulting in better hydrocarbon flow. PECNP stabilized surfactant-supercritical CO2 foam drains rapidly in the presence of crude oil, leading to good clean-up, which will result in better flow back and higher productivity.
Collapse Failure Analysis of Production String in Hydraulically Fractured Wells
Authors: Mazhar Y.. , Ighalo S.. 
Published: October 2018

Abstract
High-rate, multistage hydraulic fracturing in unconventional wells results in high internal burst loads, which are normally considered during production string design; yet, recent production casing failures exhibit casing collapse after several stages of a fracturing operation. Post-analyses of presented case studies demonstrate that production strings can be exposed to high-fracturing collapse loads caused by inadequate cement bonds around the casing.
In this study, a fracturing operation was initially simulated to obtain an actual thermal profile for casing-stress analysis with a thermal wellbore simulator. Based on available data, bottomhole treating pressure (BHTP) was calculated to match the actual field data. A load case was run to check the collapse integrity of production casing with the assumption that a casing section below the top of cement (TOC) is fully exposed to the simulated BHTP because of channels created in the casing annulus. Additionally, a sensitivity analysis was performed to identify the threshold BHTP limit that can start collapse failure. Another scenario was simulated by assuming a good cement bond for comparison with previous simulations.
Two case studies are presented wherein production casing collapse failures occurred during multistage fracturing operations. Both wells had horizontal trajectories and planned for 20 and 28 frac stages, respectively. Results based on actual field data demonstrate that the collapse safety factors were less than the design factors all the way from TOC to the casing shoe depth in case of exposure to BHTP in the casing annulus. Additionally, the sensitivity analysis highlighted that the casing collapse rating can be exceeded if exposed to even lesser BHTP than simulated and actual BHTPs. Simulations without any pressure communication to the annulus also confirmed that the potential of collapse failure becomes minimal with adequate cement bond under multistage-fracturing operations. Based on these findings, it was derived that casing collapse failures in both wells were the result of BHTP transfer into the annulus while fracturing operations. Such failures could be avoided in the future with additional design considerations during the planning phase of such wells.
This work shows the importance of additional collapse loads for production strings to improve the integrity of unconventional wellbores that are designed for multistage hydraulic fracturing operations. It is possible to ignore this load analysis if all potential operational risks are addressed with appropriate contingency designs.
Twenty Years, One Fracture and the Future of a North Sea Asset
Authors: Hoq A.. , Wishart P.. , Findlay M.. , Roy A.. , Stanley R.. , Giraud C.. , Abbott J.. , Norris M.. 
Published: October 2018

Abstract
The Andrew asset is a strategic hub for BP in the Central North Sea and has been producing from the Palaeocene oil reservoir for the past twenty-two years through a small fixed platform. In addition to the conventional Palaeocene oil reserves, there is an underlying Lower Cretaceous gas-condensate reservoir. The A11z well was drilled as an appraisal well within this low permeability formation and the original completion in 1998 was designed with the intent of performing a future hydraulic fracture. Extended well tests however, identified that gas production facilities were required for production and these were not provided until platform redevelopment in 2015. The stimulation operation has been delayed since due to the highly complex interfaces on an ageing asset and prioritisation of plant reliability work scopes and other simpler intervention work scopes.
Due to the increasing strategic importance of a new black start gas well for the asset hub, the alignment of priorities between the different functions was addressed and the hydraulic fracture operations were executed in June 2018. A multi-disciplinary project team has been established with a remit to manage and simplify the work scopes, enabling an efficient stimulation operation and a safe flowback with minimal impact to the platform reliability. The optimal design for a reliable proppant hydraulic fracture treatment has been crucial to deliver this Regional objective.
The stimulation execution was one of the largest single stage proppant placements for the basin in recent history. The implementation of single mesh proppant for the entire job is a unique deployment for the Region and a novel movement in the global stimulation industry in general, as was the first application of fibres in the North Sea. In addition to the unconventional job design, the Andrew A11z stimulation has become the first proppant fracturing treatment to be executed by BP UK North Sea in twenty-two years.
The successful execution and results of this complex project demonstrates how innovative stimulation design, when combined with effective multi-disciplinary team management and guided by aligned priorities adds significant long-term value but can also extend the life of mature offshore assets and instil confidence to pursue many more similar opportunities in such environments that are all too often discarded due to perceived complexity.
Getting More Out of Your Multistage Fracturing Openhole Completion
Authors: Bartko Kirk , Muhammad Syed , Oparin Maksim , Tineo Roberto , Al-Makarem Fadhel Abu , Desai Ankur , Ulaiw Jasim Al 
Published: October 2018

AbstractSaudi Aramco Unconventional Production Engineering Division currently performs multistage propped fracturing operations using cemented plug and perf completions, to target tight gas reservoirs requiring stimulation. To improve operational efficiency, eliminate wireline intervention and coil tubing milling operations, the decision was made to test an openhole multistage fracture system (OH MSF). This came with the challenge of ensuring adequate reservoir contact, comparable to the cemented plug and perf operations, where 21 perforation clusters, in average, are targeted.The OH MSF technology chosen consists of multiple frac ports per stage with high pressure mechanical packers to isolate each stage and slip-on oil swell packers, to isolate the individual frac port within a stage. This new method of diversion within the compartment itself helps to ensure that small variances in pressure between nozzle ports are isolated preventing the fracture operation within a stage from consolidating to a single-entry point. Like standard ball drop sleeve systems, the OH multiple entry frac sleeve system uses progressively increasing diameter balls to open each stage. One single ball will open all the ports in one stage simulating multiple clusters per stage. This allows for an increase in reservoir contact when stimulating large openhole lengths.Case Study Well-A was completed with six multi-entry stages, three entry points per stage, and one toe stage utilizing a hydraulic port resulting in a total of seven stages and 19 frac sleeves. The isolation plan for this well consisted of mechanical packers between the main nine stages and slip-on constrictors between the individual ports within each stage. Each fracture port was engineered with three jets of 0.563 in. hole diameter as part of the limited entry design. All the fracture stages were performed as per design. The initial production response was better than offset wells completed with plug and perf technique. A production log suggests contribution from 75% of each individual jet, indicating the proper diversion was achieved. Using a seven-stage openhole system yielded to 17 effective fractures contributing to production. By utilizing OH Multiple Entry MSF system technology for limited entry fracturing, Saudi Aramco has improved reservoir productivity and operation efficiency.This is the first time an openhole multistage fracturing system combining mechanical and constrictor swell packers has been deployed to promote limited entry diversion. This qualified and field-tested novel completion methodology ensures proper fracturing diversion between frac-ports located within the same stage. The benefits of this technology include improved reservoir contact, operation efficiency, cost reduction and placement improvement.