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KBR announced that its joint venture with SOCAR, who is undertaking the engineering design phase of the Azeri Central East (ACE) platform, is now nearing completion. The ACE platform is the first of its kind to be designed through all phases, from concept to front-end engineering design and detailed design, to fully use KBR’s digital twin technology. The benefits of the digital twin continue to be used as the ACE platform moves into fabrication and commissioning, which is being undertaken in Azerbaijan. Digital twin technology creates a platform for all involved in the process to access all project information from anywhere in the world through all phases. The technology allows users to view procurement status and materials availability.
Plug and Perf (PnP) completions have been the most widely used multistage hydraulic fracturing methods in unconventional wells. In a PnP completion, isolation between stages is achieved by setting frac plugs inside the horizontal liner. The number of perforation clusters and perforation holes are designed using limited entry perforating techniques.
While PnP is a proven method, there are also some downsides, particularly when considering the inability to pump plugs due to changes in casing integrity and casing deformation occurring in 20-30% of horizontal wells. Casing damage has been increasingly recognized as a challenge to well integrity in active or child wells during multistage hydraulic fracturing. Casing deformation and reduction in casing inside diameter (ID) prevent the use of PnP operations due to frac plugs being unable to pass through deformed casing.
Cemented multi-entry ball-activated fracturing sleeves (ME-BAFS) allow users to imitate the limited entry effect of PnP completions while eliminating the need to deploy large OD frac plugs for each stage. The multiple entry points are activated using various-sized frac balls dropped from the surface as the stimulation treatment is pumped, eliminating the need to rig up and rig down between stages. After fracturing is complete, the frac balls either dissolve or are flowed to surface allowing production to begin immediately eliminating through-tubing intervention. The multi-entry ball-activated fracturing sleeves use graduated balls and ball seats to open as many as five sleeves per stage with a single frac ball for increased efficiency. Number of clusters and entry points are calculated based on limited entry techniques similar to PnP.
Within this study, two limited entry techniques, PnP and multi-entry sleeve systems, are evaluated using commercial fracture modeling software, and well production modeling to compare the steady-state production between PnP and multi-entry ball-activated fracturing sleeves. Hydraulic fracture modeling is also used to evaluate limited entry perforation design, perf erosion, stress shadowing, and fracture propagation.
The recent, sustained depression in global oil prices has driven a significant reduction in upstream Exploration and Production (EandP) expenditure, particularly in the capital-intensive offshore environment. The high costs traditionally associated with EandP development projects, specifically in subsea developments, have driven a requirement for the adoption of technologies that not only increase the efficiency of the well construction process, but also reduce the total number of wells required, whilst increasing production rates and recoverable reserves.
Building on recent industry experiences with the varying multilateral systems available, Woodside implemented the use of an alternative innovative multi-lateral system, which has gone through multiple evolutions and marked improvements in system reliability and installation efficiency compared to Woodside's previous multilateral experience. The latest evolution of this system has been implemented during the construction of multi-lateral wells for the Greater Enfield Project (GEP). Within GEP, the Norton over Laverda (NoL) field development comprises three tri-lateral production wells (namely NoL01, NoL02 and NoL03). Norton field is an offset to the Vincent field, which employed an alternative multi-lateral completion design. On average, the Norton multi-lateral well operations were executed 15-30% faster than previous comparable Woodside installations. This has been attributed to the application of operational learnings from the previous Vincent multi-lateral development and the implementation of the new system. These wells were constructed in water depths of > 800 m, the deepest for such a system globally. Of the three wells, NoL01 and NoL02 were constructed well under budget, and ahead of schedule. NoL02 was constructed in a time that benchmarked as the fastest well per 1,000 m versus basin offsets. NoL03 was completed within budget, whilst having faced two major NPT (Non-Productive Time) events (ultimately resolved using world first solutions for the given system). This paper will discuss the successes, challenges experienced, and lessons learned during the installation of the three Norton tri-laterals. This field is a prime example of how new technology and the installation practices for multilateral systems within the operator's assets of the North-West margin of Australia have improved over time.
Rotary steerable systems (RSS) and steerable motors pose their own unique challenges when modelling the bottomhole assembly (BHA) directional behavior. This paper aims to present a methodology that allows the anticipation of problems such as mechanically stuck pipe or lock up situations when running in hole casing or completion strings.The methodology consists of 3 tasks: evaluation of intermediate doglegs and wellbore tortuosity using a unique Rock-Bit-BHA analysis, modelling of the casing deformation including potential centralization and then modelling the run in hole (RIH) of the completion. The directional capabilities of a BHA are affected significantly by the selection of the drilling bit, type of directional drilling driving system and the type of formation. The resulting trajectory can be either very smooth or very tortuous with significant additional local doglegs. The deformation of the casing as well as the completion post buckling analysis is completed using a robust and field validated 3D stiff string Torque & Drag & Buckling model. This methodology can be applied before, during or after the well has been drilling. Used before or during the well construction process, an indication can be given as to whether the casing or completion can reach total depth (TD) using planned or actual data. Used after a lockup or stuck pipe incident, the methodology can give an indication if tortuosity was a contributing factor. Various field cases are presented and clearly show the benefit of the methodology including post-analysis of stuck standalone-screen (SAS) completion string in complex 3D drain and pre-analysis of completion run in hole (RIH) targeting a specific drain. Correctly evaluating the risk of BHA, casing and/or completion strings getting stuck or locked-up when RIH can ultimately provide a template for ultimate reduction of non-productive time (NPT).
Multiple attempts to commercially produce from a horizontal well in a challenging sandstone formation completed with the plug-and-perf method were rendered unsuccessful. An innovative stimulation strategy was proposed for the next candidate in an attempt to improve post-fracturing productivity. Three different types of proppant fracturing treatments were performed as a first-time application, including hybrid slickwater treatment, low-guar crosslinked treatment, and CO2 foam fracturing.
A hybrid design combining high-rate slickwater at the beginning and low-guar-loading crosslinked gel at the end of the treatment was pumped in two stages. This allowed minimizing the crosslinked fluid pumped while enhancing fracture half-length. Second, conventional low-guar fracturing was implemented in four stages. Crosslinked gel loading was reduced by 25% compared to gel that was utilized in offset wells. Finally, a CO2 foam fracturing design with a novel biopolymer linear fracturing fluid was implemented in the last stage. This reduced water consumption and improved the chance of increased gas production by yielding a higher-conductivity fracture network.
Friction pressure for CO2 foam was calibrated using bottomhole gauge data that was obtained with downhole gauges run prior to the calibration testing. The new calibrated friction numbers were then used for the bottomhole treating pressure calculation during the treatment. CO2 foam fracturing was found to be a significant success for this well based on multiple evaluation criteria. First, the use of foam helped conserve 1,000 bbl of freshwater compared to conventional stages. Second, the foam treatment allowed two times faster cleanup compared to other stages, based on cleanup time normalized over fluid volumes. Finally, production logging results showed that the foamed treatment achieved better production compared to other treatments in the well, considering productivity index (PI) normalized by the proppant mass, porosity, and zone mobility. The CO2 stage normalized PI was significantly higher than the other stages in the well. After the well was cleaned up, a production log was conducted, and it was analyzed to corroborate the higher production: 70% of the production contribution was seen from the CO2 treatment interval.
In most of the literature, estimates of the friction correlations for foams are based on empirical data. This paper gives the calculations of friction pressure based on field data. The combination of measured bottomhole data and post-cleanup production logging demonstrates the potential productivity improvements that can be achieved through novel design approaches. This type of data is rare in the industry and can help to improve the design of foamed fracturing treatments.
Successful reservoir surveillance is a key component to effectively manage any field production strategy. For open hole extended reach horizontal wells, including some wells over 30,000 ft in length, the challenges to successfully deploy real-time logging tools are greatly magnified. This is further complicated by constraints in the completion where Electrical Submersible Pumps (ESP's) are installed. A comparative review of the latest technologies and methods available to overcome these challenges will be explored.
The challenges are formidable and extensive; logging these extreme lengths in cased hole would be difficult enough, but are considerably exaggerated in the open-hole condition. The logging run in open hole must also contend with increased frictional forces, high dogleg severity, washouts and an increased well bore rugosity. The main challenges to achieve the logging objectives in open hole extended reach wells, are 2-fold, namely;
To log the entire open hole section and reach the Total Depth (TD) of the well. To obtain high quality data from the logging tools, despite the adverse downhole environment.
To log the entire open hole section and reach the Total Depth (TD) of the well.
To obtain high quality data from the logging tools, despite the adverse downhole environment.
To achieve these 2 main objectives, a comprehensive approach is taken while designing the logging operation. The choices available to deploy the logging tools are mainly on electric-line cable with an electric powered tractor or on coil tubing with a hydraulically powered tractor. The most common type of log performed in these extended reach wells is a production log to measure multi-phase inflow contributions. To improve the success rate of the logs, a number of initiatives have been implemented, including deployment of custom designed coil tubing tractors and state of the art wireline tractors. The logging tools and job programs are adapted based on the results of simulations, accounting for many variables, including the completion, well type, deviation and target depth.
The ability to successfully log these extended reach wells cannot be understated, reservoir simulations and management decisions can only as good as the quality of data available. Some of the advantages of drilling mega reach wells such as increased reservoir contact, reduced footprint and less wells drilled will be lost if adequate reservoir surveillance cannot be achieved. To meet the key objectives, creative solutions including designing and upgrading the best fit for purpose technologies are applied for the extended reach wells. These steps taken not only improve the overall logging performance, they can also result in cost savings by avoiding multiple unsuccessful logging runs.
Gupta, Vaibhav (Schlumberger) | Jeanpert, Julie (Schlumberger) | John, Colin (Reliance Industries Limited) | Bose, Ramen (Reliance Industries Limited) | Agrawal, Vivek (Reliance Industries Limited) | Patowary, Markandeya (Reliance Industries Limited) | Banka, Raushan (Reliance Industries Limited)
Openhole gravel pack is the preferred completion method of sand control in unconsolidated deepwater formations with sanding tendencies. The design phase of an openhole gravel pack treatment spans drilling of the reservoir section, wellbore preparation, sand screen installation, gravel placement, and well flowback. This paper discusses several ultra-deepwater wells of India, where openhole gravel packs were performed by integrating drilling, wellbore cleanout, wellbore displacement and gravel pack methodologies to achieve a holistic approach towards openhole gravel pack completions.
The reservoir sections were drilled with streaks of shale and dolomite sections, the liner shoe often landing in shale, exposing a shaly rat hole. Next, the wells were displaced to dedicated production screen testing (PST) mud prior to running in screens. Screens were then placed across the openhole with memory gauges to capture downhole events during the gravel pack. The displacement pills train was engineered to displace the open hole with water-based fluid prior to starting the gravel-pack treatment. Extensive lab testing and displacement simulations for efficient spotting of pills and optimal sweeping effect were performed. The gravel-pack treatment was executed using Alternate Path technology and a high-temperature viscoelastic surfactant (VES) carrier fluid system.
11 ultra-deepwater wells off the east coast of India were completed. Displacement of open hole from drilling fluid to water-based system was done with direct displacement and reverse displacement methods. Due to the narrow fracturing window of 200-300 psi in all the wells, bottomhole pressures were managed by deploying multiple techniques such as using a lighter VES-based brine, optimizing the rheology of the fluid and taking returns through the riser. Roping behavior of the pre-pad and slurry have also been studied, and results presented to correlate with design. All open-hole gravel packs were executed without losses and achieved complete packs. Finally, flowback and well test data were analyzed by the operator and found to be as expected with no sand ingression. A holistic approach toward open-hole gravel-pack treatments has been developed, analyzing all the interlinked elements and the efficacy of the design process verified against surface and downhole data gathered for each well.
This paper discusses the approach, simulations, lab testing, and evaluation, analyzing captured data from drilling phase of the open hole to completing the well by placing gravel across the screens and flowing back. The design approach, integration strategies, and lessons learned in these wells offshore India can be applied to improve success rates of sand control completion wells around the world.
Achieving complete and efficient gravel packing is the primary objective when tasked to install an effective sand control completion. This paper describes the challenges faced during the selection, design, planning and execution phases of the open-hole horizontal gravel pack completions in the "L" field, offshore Republic of Congo. The open hole gravel packs (OHGPs) targeted the most prolific sand to ensure production objectives were achieved with the benefit of a gravel-pack completion.
The operator completed two OHGPs with alpha/beta technique for the sand face completion utilizing concentric annular pack screen (CAPS), wire-wrap screens, and a service tool permitting post-gravel pack filter cake clean-up treatments. The accurate selection, modeling, and evaluation of sand control techniques were crucial for completion and production optimization, as well as risk minimization. The service approach had traditionally leveraged upon industry rules of thumb and previous experience, but as the reservoir section length increased and completion configuration became more complex, the error margins tightened and the cost of failure increased such that a more robust design approach was needed.
This paper addresses several key factors that must be considered carefully when installing a successful gravel pack completion. The dynamic pressure management becomes critical to maintain the bottom hole pressures within a required range for the successful implementation of the gravel pack. Other factors include designing an optimal screen-wash pipe annulus ratio during alpha-beta wave packing, an optimal alpha wave height, and the use of multiple beta wave packing rates.
Results from the preliminary modelling of the gravel pack pumping provided an accurate estimation of the maximum and minimum anticipated pumping rates and pressures. These parameter estimates were generated for the workstring design scenarios and provided guidance for the planned pumping rate adjustment during the gravel packing execution phases. The gravel packed wells achieved pack efficiency greater than 100% based on an estimated 8.5-in. diameter OH. Post completion multi-rate tests concluded potential productivity exceeding the operator's expectations.
This paper describes the lessons learned and best practices developed for offshore Congo open-hole gravels packs, which have a very challenging well completion and reservoir scenario. Several proven completion practices are reviewed, with a critical examination of the application of these scenarios for future completion operations in this difficult operating environment. This applied methodology has made significant impact on future field development and increased the production expectations for the asset.
Ritschel, Robert (Wintershall DEA) | Storhaug, Jens (Wintershall DEA) | Dahle, Bjorn Olav (Ridge A/S) | Meschke, Frank (3M) | Barth, Peter (3M) | Jackson, Steven Richard (3M) | Gundemoni, Bhargava Ram (3M) | Danielsen, Trond Helge (3M)
The Dvalin gas field is located in the Norwegian sea on NCS and is operated by Wintershall DEA Norge. It is supported by two independent reservoir structures, Dvalin East and Dvalin West. The field was explored through wells 14S and 15S in 2010 and 2012, respectively. The field is characterized by dry gas, high CO2, high temperature (160 °C) and high pressure (SIWHP 620 bar). The targeted Garn sandstone has good reservoir quality, but with a high permeability contrast.
The field development was sanctioned in 2016 and calls for a 4 well solution through a centrally located subsea template, producing gas back to the host platform Heidrun TLP 15 km away. Water depth at location is 380 m and targeted reservoirs are at 4140 m MSL (East) and 4240 m MSL (West).
Production plateau rates are estimated to be approximately 106 MMscf/D (3 million std m3/d) per well where thin high-permeability zones within the Garn formation are expected to dominate the inflow. The lateral facies development is thought to be relatively homogenous throughout the field, thus S-shape wells falling off to vertical through the reservoir will ensure effective drainage.
Sand failure is expected after short time of production and would increase the risk of erosion causing severe damage to well jewelry and production facilities. It has been decided to integrate sand screens as a means of downhole sand control as part of the primary lower completion design. The sand screens will offer sand control, erosion resistance, hot spotting resistance as well as robustness towards a full hole collapse during reservoir pressure depletion. As the subsea completions are carried out from a mobile drilling unit in harsh environments, protection of the sand control filter media during installation is of utmost importance.
This paper will describe the selection process of sand control and qualification steps carried out to use ceramic screens as the stand-alone screen solution for successful deployment and integrity for the Dvalin field development
ADNOC Offshore started-up full field gas-lift activation for the first time in 2020. This major step will unlock field's potential by increasing reservoir withdrawal and increasing wells life by mitigating water production / breakthrough. This paper details the successful application of gas-lift from design during appraisal phase and early production stage to full field implementation. Fit for purpose design was implemented through multi-disciplinary studies and work. A strong change management in operating philosophy was requested to take onboard all stakeholders: Field development, Field Operation, Wells operation, Drilling and completion. Following appraisal and early production phases on a green field, wells design was optimized to ensure proper activation in most of the producers (two over three reservoirs developed). Due to full field development phasing, the first 30% of the wells completion were designed based on early production phase data. Before full field commissioning started, in well gas-lift valves were designed and installed, integrating all the dynamic information gathered during natural flow production. Valves change out was performed with the highest HSE standards, and taking into account full field development timing in order to reduce downtime and therefor maximize production. As gas-lift is new in the operating company, a strong change management was required: operating with gas-lift by field operation team, Completion design, Drilling and Gas-lift Production with SIMOPS. Gas Lift implementation will ensure the future oil production of the field as water injection and production will increase. Gas-lift practice implementation led to modifying the operating company's rules in multiple and deep aspects:
Improve field team competencies in handling high pressure gas-lift system, Increase completion and wells operation complexity, Implement new SIMOPS rules.
Improve field team competencies in handling high pressure gas-lift system,
Increase completion and wells operation complexity,
Implement new SIMOPS rules.
As a first achievement, one well under reservoir integrity issue (low productivity due to reservoir collapse) was re-activated and production of existing wells was increased of several thousands baril. Further increase in production is expected in the following months as implementation is deployed to all required wells.