The Jasmine oil field, in the Gulf of Thailand, has several pools of unconsolidated sandstone reservoirs. Multi-zone completion is usually deployed in these reservoirs, however, sand control in this completion type could be a challenge. Several sand control techniques were evaluated and the most promising strategy was found to be chemical sand consolidation treatment. In the design phase, the most critical challenge was to determine the optimal and safe chemical recipe and placement technique. A single chemical recipe optimized for all of the reservoirs was achieved, yielding an unconfined compressive strength (UCS) of at least 500 psi while retaining a permeability of 40%. Bullheading was selected as the placement technique. To minimize contamination of the chemical with annulus fluid, we designed to shorten the distance between the packers of each completion zone. Cut-to-release packers were used instead of pull-to-release packers to mitigate the concern of unwittingly unsettling the packers. A risk assessment was conducted to cover all aspects of the job. High risk activity like pumping flammable fluids at high pressure was specifically singled out and special mitigation was put in place to ensure a safe execution of the activity. Some other mitigations such as minimizing nearby hot surface areas, real-time monitoring of oxygen levels, and purging the mixing system with CO2 were also considered. This paper provides a case study for chemical sand consolidation treatment from the view of an oil company and covers the full lifecycle of the application from concept selection to the finalized procedure, taking into account both technical and operational considerations. This research contributes to the public body of knowledge within the oil and gas industry with regards to an emerging technique for sand consolidation.

The scope of this paper is to discuss and compare the different milling strategies of the frac plugs associated to hydraulic fracturing operations in both, vertical and horizontal gas wells, with formations depleted in Petroleum Development Oman (PDO); the main objective is to describe milling operations and the well delivery improvement by the optimization of clean out and milling strategy. The paper will show the enhancement of the milling operations and the outstanding results. The paper will start by describing the execution of hydraulic fracturing operations in both vertical and horizontal wells, which is mainly related to plug and perf. It will also cover clean out and milling practices for frac plugs in depleted formations. Further, it will discuss the planning and design of the post frac clean outs and milling jobs based on the learnings previously captured. Frac plugs milling operations have been successfully improved in severe depleted vertical gas wells and some horizontal wells with no severe depletion; initially the milling operation was done after all frac stages were completed in depleted wells, out of the critical path, however the experience showed that it was a lengthy and expensive process due to the severe formation losses while milling leading into a very low efficient operation impacting the frac well delivery. The subsequent step was to address the milling after every stage, during the critical path, which increases the cost of daily frac charges. With the use of an innovate downhole technology the milling strategy was changed and optimized showing outstanding results, milling frac plugs was achieved successfully at the end of the job in horizontal wells while in some previous wells the milling was done in between the stages; also for vertical depleted gas wells, fracturing stages have been combined to mill frac plugs together. The completion of the entire wells (well delivery) was achieved in a relative shorter period of time compared to previous wells; this is reflected on actual cost reduction of more than 20% of total cost/AFE The optimization of the frac plug milling operations is a novel approach to enhance hydraulic fracturing and well delivery in depleted gas wells in PDO, this is in alignment with the continuous improvement (CI) ideas and the lean thinking across the oil and gas industry nowadays. It is easy to replicate in other gas fields expected to be depleted, which will reduce cost, Health, Safety & Environment (HSE) exposure and will help increase the recovery of hydrocarbon reserves.

Interest is high to reliably run single-trip completions without involving complex/expensive technologies. The reward: significantly reduced rig time and completion costs. As described herein, a unique pressure-activated sliding side door (PSSD) valve was developed and field-tested to open without intervention after completion is circulated to TD and liner hanger and open-hole isolation packers are set. A field-proven sliding-sleeve valve that required shifting via a shifting tool run on coil tubing, slickline or wire-line, was upgraded to open automatically after relieving tubing pressure once packers (and/or liner hanger) are set. This PSSD technology, which is integrable to any type of sand control screen, is equipped with back-up contingency should the primary mechanism fail to open. Once opened, the installed PSSDs can be shifted mechanically with unlimited frequency. The two-or three-position valve can be integrated with ICDs (includes AICDs/AICVs) and allows mechanical shifting at any time after installation to close, stimulate or adjust ICD settings. After a computer-aided design stage to achieve all the operational/mechanical requirements, prototypes were built and tested, followed by several field installations. The design stage provided some challenges even though the pressure-activation feature was being added to a mature/proven SSD technology. Prototype testing in a full-scale vertical test well proved invaluable as it revealed failure mode that could not have appeared in the smaller-scale lab test facilities. Lessons learned from the first field trial helped improve onsite handling procedures. PLT logs run on first installation confirmed the PSSDs with ICDs opened as designed. The second field installation involved a different size and configuration, where PSSDs with ICDs performed as designed. The unique two-or three-position PSSD accommodates any type of sand control or debris screen and any type of ICD for production/injection, which can be easily adjusted at the wellsite. The scope of application is extremely broad. Consequently, more wells that normally could not justify the expense of existing single-trip completion technologies can now benefit from the enormous cost savings of single-trip completions, including ones that require ICD and stimulation options.

This paper shows the results from chemical sand consolidation treatments used in the M1 sandstone as the main sand control method. For a successful implementation of this technique a workflow that combines field data, temperature modeling, laboratory analysis, petrophysics and geomechanics has been developed. Production results reports zero to near zero sand production with almost no impact on well productivity. Pre job design steps used to secure a consolidated reservoir after the treatment are described. Temperature is a key parameter to model since the resin is temperature activated. Laboratory tests and simulated temperature defines the curing time. A step rate test is used to calculate the injectivity index and evaluate the need for an acid stimulation treatment before the consolidation system is pumped into the well. This test is repeated after curing time to evaluate any possible impact on productivity. Determination of the Unconfined Compressive Strength (UCS) of the consolidation sand and critical sand production rate are also included in the analysis to understand sand production potential in the field. Chemical sand consolidation consists of two main components, resin and hardener. The consolidation fluid along with a pre-flush and an over-flush have typically been pumped into the well using production tubing. This sand control method has been proven to be relatively low in cost compared to other sand control techniques and the treatment can be performed in a relatively short period of time. These two characteristics and the positive production results observed thus far makes this technique attractive for upcoming sand control completions with unconsolidated reservoirs with similar characteristics to the M1 sandstone. In addition, conventional sand control methods rely on a particle size distribution (PSD) from a representative core sample for a successful implementation whereas chemical sand consolidation system is PDS independent.

The final goal in a perforation operation is achieving the maximum production and reducing perforation damage, using optimal completion process. The Dynamic Underbalanced Perforation (DUP) as one of the more recent completion technologies minimizes or even eliminates the perforation crushed zone by optimizing the well's dynamic underbalance. Dynamic underbalance is a transient underbalance process that occurs immediately after creation of the perforation tunnels. The modeling of this process is essential in designing the optimal configuration of the perforation charges to evaluate the perforation efficiency. In this study we propose a novel and efficient numerical method, to optimize the completion efficiency which is rarely attended in the literature. There are five main steps in our modeling procedure: Calculating volume of the gas released in detonation, Calculating inner temperature of the Gun, Calculating remaining gas and energy amount inside the gun, Calculating pressure and casing stability analysis, and finally Calculating perforation skin. Although there are some computer programs that claim to model the DUP technology, none of them uses a fully numerical method. In fact, all of these programs use experimental data and correlations to predict the efficiency of this process.

Abstract This paper will portray the development and deployment of remote-activated sliding sleeve devices commissioned for use in a two-stage completion North Sea project. The sliding sleeves are required within the lower completion to provide access to the reservoir, protection to a control line and act as part of the fluid-loss envelope. Remote activation technology has been implemented to the sleeve designs to improve efficiency and introduce operational flexibility. Three variants of sleeves were designed and deployed to facilitate well objectives. The first variant is run-in-hole (RIH) Open to provide a circulation path and subsequently closed post displacement activities. The second variant is RIH Closed and is distributed across the reservoir. These sleeves are remotely opened post Xmas tree installation and provide the tubing/annulus communication for production or injection. The third variant is again RIH Closed, but this is a purely mechanical sleeve to allow further access to compartments or different reservoir units later in the well's life. A variant of open-hole anchor with bypass capability was also developed and tested. Remote-activated sliding sleeves were prototyped and qualified to API 19AC. In addition to the standard requirements of API 19AC, open/close cycles were also performed with lost circulation material-laden (LCM) fluid along with low hydrostatic pressure function testing. This latter testing is to allow for sequential functioning without having to shut in or choke back the well, instead functioning while the well is flowing or even under full operational drawdown. Three wells have been completed to date, two producers and one injector. The RIH Open sleeves have successfully acted as a replacement to a traditional fluid loss valve and the RIH Closed sleeves have allowed zonal isolation, selective water shut-off and reservoir management. The use of open-hole anchors has also been standardised, in producers to support future stimulation operations and in injectors to combat thermal contraction. Across all three wells the RIH Open sleeves have all been actuated successfully via Radio Frequency Identification (RFID) tag carrier or timer and the RIH Closed via pressure sequence and / or timer. The second producer also saw the first implementation of the staged clean-up functionality with sleeves opening at four different intervals over a period of 17 days.

Abstract For the past few years ADNOC has extensively ramped up its effort in exploring and testing unconventional reservoir across Abu Dhabi tight oil and shale gas formation as part of its oil & gas 2030 strategy. Shilaif tight oil exploration started over 5 years ago with multiple vertical wells drilled and tested allowing discovery of stacked tight oil play with significant resources in place. To unlock these resources, horizontal drilling and multistage fracturing were used to confirm recoverable resources, and well potential. Prolific production results have since propelled hydraulic fracturing, hence it has become imperative to build a process to standardize unconventional fracturing technical and operational requirements and to maximize efficiency and benefit. A prime example of such process was in Huwaila-68 where the organic-rich Shilaif shale/tight oil formation was targeted. A target that is analogous to the Eagle Ford from the same Late Cretaceous age. A significant weight is put on reservoir quality assessment to minimize margin of error and increase the probability of fracturing success, and to maximize recovery of the estimated tight oil and shale gas in place. This process assessed the Shilaif from a geological, petrophysical, and geomechanical perspectives. This was followed by setting up preferential staging and perforation placement strategy for fracturing based on reservoir and completion quality which correlated to an initially built 1D mechanical earth model. Production forecasting using reservoir simulations were also utilized to assess fracturing success and deliverability. The processes above led to completing multistage fracturing in Huwaila-68 within the Shilaif formation by means of a pump- down perf and plug operation coupled with high rate slick water pumping, which was followed by extensive well testing. Operational efficiency allowed for the completion of 27 stages placing in excess of 7.3 million lbs of proppant. The use of chemical tracers as a qualitative measure allowed for correlation between natural fracture presence, recorded pumping events, and initially recorded gas shows while drilling. Such observations would help in well placement for future horizontal wells. Post fracturing production rates have met expectations, and were in line with the initial reservoir assessment predictions. The novelty of this paper is the inclusion of several domains to reduce the error margin of fracturing unconventional formations such as the Shilaif. Being an area where field development is rapidly taking place, the inclusion of new technologies have become persistent, and these were evident from the reservoir assessment phase, through to the fracturing phase, and ending with the well testing phase. This level of data gathering and assessment will act as a benchmark for all future unconventional fracturing within the UAE while lessons learnt will further enhance the turnover from drilling to production.

Abstract The objective of this study is to provide an overview of recent waterless stimulation focusing on hydraulic fracturing technologies, advantages and disadvantages, limitations, and new technologies under development. Different technologies are presented including proppant-free such as slurry fracturing and in-situ proppant generation, CO2, LPG, Seawater, plasma fracturing, high power lasers, gas stimulation, exothermic reactants, and high energy gas fracturing. Water-based hydraulic fracturing is commonly used stimulations to recover hydrocarbon specifically from the tight formation. The unconventional reservoir requires pumping and fracturing multistage to maximize stimulated reservoir volume. This technology involves the use of large volumes of high water quality, pumping at high pressure, and filling up the fractures with proppants. Several technologies are presented in an effort to find alternatives to current water-based fracturing technologies. The industry efforts towards waterless fracturing technology are to adapt different technologies into fracturing, for example, the use of plasma to create fractures. The principle of this technology is to store large electric charges and release them in a very short period. Another technology is based on gas combustion to create pressurized gas, which can then create fractures in the reservoir, the use of high-energy laser is used for fracture initiation, and in-situ proppants are targeting chemicals that generate proppant in the fractures. Jetting is also evaluated where acid is injected at a high rate for deeper penetration to create network tunnels. Exothermic fracturing is also discussed which is a technology based on chemical reactions that are triggered at downhole temperatures releasing pressurized gases and creating fractures. Once the drilling operations of a well are concluded, the well is then completed and stimulated. A typical scenario is to perforate the well using a shaped charge perforating gun followed by acid or hydraulic fracturing to maximize reservoir contact. A considerable reduction in permeability can occur when using conventional shaped charge gun, when the fracturing fluid formulation is not appropriately designed, or when improperly flowing back the fracturing fluids. A thorough investigation of recent non-damaging waterless stimulation technologies is included as an alternative to shaped charge gun perforation or to fracturing with water. If conventional fracturing is to be used regardless, then these technologies can be used to help initiate the fracture by lowering the formation breakdown pressure. In addition, it is possible to use these technologies in producing wells to enhance productivity. The discussion will provide details of each technology: suitable use scenario, methodology of use, limitations, and results of case studies. As more and more wells require stimulation to be produced commercially, new non-damaging waterless methods are implemented. The importance of this paper is to show these alternative technologies to increase production and minimize damage to reservoirs.

Abstract Recent development of horizontal well completions and stimulation methods enhanced the development of conventional and unconventional resources. Multistage fracturing allowed oil and gas operators to stimulate long laterals in continuous and efficient operations that increase the reservoir contact, thus increasing the recovery of oil and gas. Oil and gas operators work to improve the efficiency of multistage fracturing treatments by developing and integrating enabler hardware, processes and chemical technologies to enhance the fracturing operations and reduce cost. This paper reviews and discusses the different types of horizontal wells with multistage fracturing completions and stimulation techniques including plug-and-perf, abrasive jetting, just-in-time perforation, sliding sleeve systems, coiled-tubing conveyed fracturing systems and annular isolation methods. The efficiency of the multistage fracturing treatments depends on multiple factors comprising the operational time and cost associated with different type of completions such as plugs and sleeves, different intervention operations such as wireline or coiled-tubing and different stage distribution and pumping designs. Combination of multiple multistage fracturing methods resulted in hybrid cost-effective treatments. In addition, multistage fracturing fluids diversions contribute significantly to the stimulation efficiency. Different types of diversion methods are discussed for each stimulation system. This paper provides a comprehensive summary of the operational practices, fracturing methods, and different multistage fracturing completions in horizontal wells while emphasizing on the recent advancements available in the market. The ability to develop an efficient and effective multistage fracturing operation is based on understanding the reservoir requirements, and identifying logistical and resource challenges at the geological location where the operation is taking place. The developed solutions would be an integration of currently available process, with proper completions, materials and development of innovative enabler technologies to accomplish optimum procedures. In recent years, several enabler technologies were developed to address the challenges within the existing multistage fracturing operations. The electronic monobore sliding sleeve was developed to address the limitation caused by small ball seat (baffle) in ball actuated sliding sleeve completions. Plug-and-perf operation was enhanced by applying the Just-In Time Perforation (JITP) method by developing a new perforation gun assembly that cuts operation time. Development of autonomous completion elements with the ability to navigate and self-destruct after accomplishing the job helped to reduce the number of trips into the well that greatly affected the operation efficiency. Completion elements and diverters built from dissolvable materials eliminated the drill-out and cleanout operations, which reflect positively on the efficiency of the fracturing process. Reviewing current advancements of multistage fracturing completions and treatments can pave the way for further operation optimization and cost reduction.

Abstract The paper describes the execution of a successful rigless intervention solution deployed to establish well integrity and restore well production in a field in Europe. The paper will go through the planning and execution of the job highlighting the criticalities encountered and the overall benefit of the activity. The approach used was a deep analysis of the well integrity issue from several prospectives. A new opportunity in the production optimization fluid has been identified. After an open discussion between Customer and contractor, a customized blend and detailed pumping procedure was agreed upon to reach the final scope. An injectivity test was executed to align the procedure to the reservoir and well behavior. Several pressure tests were performed to confirm the remedial job in place, and, after that, the well was re-perforated and opened to the production. The horizontal well described in the paper, shut in during 2016 due to formation damage and depletion was selected for a new through tubing perforations interval by coiled tubing in the horizontal section. An unexpected firing head activation occurred at an unplanned depth, just above production packer. This event produced communication across the production tubing, liner, casing, and formation, which immediately induced total losses into the naturally fractured carbonate reservoir causing well control issues. The accidental perforations could have jeopardized the final scope of the project with no oil production and premature well abandonment. A successful rigless remedial intervention was immediately executed to restore well integrity by using a real time fiber optic coiled tubing acquisition and a new conformance fluid combined with a customized cement packer technique. The remedial intervention allowed the operator to resume the initial project's scope of opening the new perforation intervals, restoring an important oil production of about 150 [m3/d]. The final solution utilized a product with unique thixotropic properties which was then engineered for production optimization using a detailed pumping strategy. This novel approach added significant value, as the operator was able to restore the integrity of the well in rigless mode, avoiding the associated rig cost.

Abstract This paper will describe pre and post workover well diagnostic and the successful water shut-off that has resulted. It also talks about the post workover survey. The well was recently completed to a new targeted reservoir and suffered from high water cut (80%) at the start of production. Proper diagnostics identified the source of water and helped in planning a successful remedial job. After water shut off the water cut dropped to zero. Post workover evaluation confirmed production from the targeted interval. Comprehensive diagnostics are crucial to designing a proper remedial job. A conventional PLT survey will describe the flow characteristics and parameters inside the wellbore only. During the job under consideration, two additional services were deployed; the Spectral Noise Logging and the High Precision Temperature sensing. Their combination with the PLT allows for the assessment of behind casing flow and the identification of active streaks of the formation. The quantification of flow rate behind casing is also achieved by modelling the temperature response from the high precision sensor. The first survey was conducted with the conventional PLT to identify the source of water. Subsequently, a high precision temperature and spectral noise log were recorded under flowing, transient, and shut-in conditions. A crossflow behind casing from the upper unperforated intervals was identified. The main liquid production is coming from the water-bearing formation that is located 15 ft above the targeted reservoir. The cement evaluation surveys that were run previously confirmed the presence of a cement channel above of the perforated interval. Based on these conclusions a remedial job was designed and conducted successfully. Another HPT/SNL survey was conducted post workover. It confirmed the absence of any further flow behind casing and that all liquid production is happening from the targeted reservoir. Surface test data showed a rapid decrease in water production to 1% post workover. This paper highlights the importance of complementing the current practice of running conventional PL surveys with two additional services: the Spectral Noise Logging and Temperature simulation/modelling using a High Precision Temperature measurement.

Abstract Halfaya oilfield in Iraq, discovered in 1976, contains multiple vertically stacked reservoirs. Currently main oil reservoirs are under primary development. The remaining deepest high GOR, HP/HT carbonate reservoir with original pressure gradient of 0.867 psi/ft has been drilled, tested, but undeveloped. An innovative production strategy has been put forward highlighting that high GOR crude can be injected into the upper oil reservoirs with partially pressure depletion, as energy-conservation measure, in view of its high wellhead pressure and good productivity during drill stem tests, therefore to achieve production enhancement and synergy among reservoirs. In-house studies indicate high GOR crude can be miscible with all oils from eight zones. Field results show that injection processes can bring dead wells back production, yielding the prolific output. Also, water cut can be reduced immediately and field water cut rising trend can be mitigated. The innovative injection processes are illustrated as follows: New development wells should be deployed at updip positions to penetrate the all the hydrocarbon reservoirs with the thick pay. Run tubing string with packer. Packer is used for isolation of upper oil zones and HP/HT environment. Huff and puff process. After perforation, high GOR crude travels up the tubing string, via surface choke and a manifold with flow meter, then enter the annulus. Choke regulates the injection rate. For low-permeability (<0.1md) carbonate reservoir, e.g., Sadi reservoir, huff and puff processes are applied post multistage fracturing treatment. High GOR flood is preferred in majorly producing reservoirs with high productivity and relatively low GOR, e.g. Mishrif reservoir. Injected high GOR crude (API=32.7) can dilute remaining oil (API=19.1-23.0), reduce its viscosity, and therefore achieve production enhancement. During primary development, asphaltene deposit occurred and chemical inhibitor has been applied. After oil blending, the risk of asphaltene deposit could be minimized. First perforate lower-pressure oil zones and then open the HP/HT zone for work safety. The production enhancement strategy and processes in this paper could be of strong reference value to similar stacked reservoirs.

Abstract Sand production in oil/gas wells is an important topic wherein a proper engineering planning is required either to avoid, control or manage it. Ignoring this phenomenon may lead to an unfavorable impact on the overall economics of the field development with additional costs incurred to fix the issues at a later stage. Sand production is normally manifested due to sandstone rock failure. The failure sometimes only manifests at later stages of hydrocarbon production associated to depletion (stress evolution). Therefore, finding the root cause of the failure mechanism and routes to avoid it, is essential. In order to achieve this objective, a proper sand production prediction analysis is required using a geomechanical model. Selection of methodology and technology will be key for accuracy of the prediction, analysis and solution. We proposed a few techniques in this article, that can be adopted during the process to design the best engineering solutions to mitigate sand production. Both simple analytical models and advanced FEM numerical models have been discussed in the paper. The selection of methodology should be based on the overall sand production risk level even though FEM techniques is the best for solving the problem.

Abstract Rigless well commissioning is an important stage of well completion to deliver a new drilled or worked-over wells (oil producer or water/gas injector) ready for production or injection. Rigless well commissioning employs firstly slick wireline intervention for well accessibility verification, down hole safety valve operability, bottom hole pressure and fluid gradient survey that assists to design the flow to clean commissioning program. Secondly, it employs coiled tubing (CT) and flow to clean (FTC) packages to cleanup the well and if necessary to perform matrix acidizing to improve well productivity or injectivity. This paper highlights operational constraints of well commissioning and its effective approach from job design, execution and evaluation that have been performed over 250 wells in the span of 5 years operations. The commissioned wells are drilled in the carbonate formation with surface clustered operation in Onshore and Offshore Artificial Islands. It also describes HSE challenges that have been faced in safe handling of return fluid, management of volatile recovered crude oil, simultaneous operations (SIMOPS) with Drilling Rig, Project and Construction (P&C) activities and hydrocarbon flaring in the environmentally sensitive area. The implemented approach and methodology of well commissioning has evolved significantly to address operational challenges and reducing well commissioning cost by 60%. It proves improvement of operating efficiency of CT and FTC packages based on downhole pressure survey, smart well commissioning, eliminating high risk clean-up operation for injector well, cluster based well commissioning, in-situ return fluid management and arrangement of vertical flare stack in the constraint offshore artificial island. The overall outcomes have achieved technical objective with optimized cost and minimum risk, enhancing rigless package utilization and implementing sustainable and effective field rigless commissioning.

Abstract Proppant flowback from hydraulic fracturing is widespread and costly due to erosion and/or blockage of producing hydrocarbons due to proppant accumulation. One remedy is to install sand control equipment integrated into a sliding sleeve device (SSD) as part of the completion string, which raises concern about erosion during fracturing. While some installations have been successful, at least one experienced sand control failure. Computational Fluid Dynamics (CFD) was deployed to evaluate the root cause and identify more robust designs, as presented herein. Firstly, we identified the most probable causes of sand control failure during multistage fracturing (MSF) in openhole (OH) horizontals. State-of-the-art CFD simulations were then performed on the installed design using actual flow conditions (rates, slurry properties, treatment time) from a failed installation. The static CFD methodology in an initial undeformed geometry proved to be ultra-conservative, so a new quasi dynamic mesh (QDM) methodology was developed, which yielded more realistic (albeit still conservative) erosion-depth predictions. The results revealed areas for improving the design of key components, and CFD was re-run to confirm erosion resistance targets. The modifications were then implemented for a field trial. Since frack location between two openhole packers is unknown, and the frack port is located between multiple screen/SSD assemblies, one must consider annular flow across the assembly in both directions. Accurate CFD predictions of erosion of completion components versus time during MSF in OH proved challenging. The quicker static methods were useful in ruling out some components as problem areas, such as the sand control media, but proved overly conservative on other key components. The QDM methodology gave more realistic results and indicated that erosion depths in specific locations could be deep enough to possibly cause sand control failure. To reduce the erosion risk, such components were modified, and the result was a reduction in predicted erosion depths to acceptable levels. A safety factor was already built into the predictions because of two key conservative assumptions: ignored initially were 1) particle-particle interaction and 2) erosion of the reservoir wall. The former was further investigated. While waiting for the field trial results, the main conclusion thus far is that CFD is a valuable tool for diagnosing erosion failures and improving equipment design. However, it’s essential to use a methodology that realistically captures downhole conditions. Presented herein is a more robust design of a screen/SSD assembly for proppant flowback control, as well as an improved CFD methodology for diagnosing sand control failures during MSF and for identifying design improvements of completion equipment. Furthermore, the inherent challenges of controlling proppant flowback without causing erosion or flow blockage of hydrocarbons are discussed.

Abstract This paper presents a state-of-the-art, automated gas lifted smart completion design, installed safely using Side Mounted Guns (SMG) to reduce well control risks for a carbonate field in Sarawak with a dominant threat of karst losses. It demonstrates how an SMG system was used to decrease installation time and minimize formation damage. The new 3D finite element software technique represents a step change in the ability to predict shock loading from complicated perforating systems and the subsequent effect on downhole completion components. Several challenges were addressed at the planning phase of the project, including the use of a new 3D finite element software to evaluate dynamic perforating shock loading and determine the optimal distance to safely place the key completion components in the well. A variety of system integration tests (SITs) were also introduced to verify compatibility of the SMG system in highly deviated well conditions and deploying through casing with inner diameter changes. Three wells have been successfully perforated with a long tubing-conveyed SMG system along with the smart well completion components, such as an inflow control valve (ICV), downhole pressure gauges, and seal assembly, which were then tested as fully functional after the gun detonation. During the well cleanup operation, the perforated gas cap was successfully used to lift the oil from the reservoir underneath the gas cap as an in-situ gas lift.

Abstract The proposal of this paper is to share the knowledge learned in this new procedure and techniques implemented in HP/HT Unconventional wells, created by the Unconventional (UC) Drilling Department at Abu Dhabi which involve around ten different services, where each has a high importance and contribution for the collective success of the well at the moment to frac and hence the feasibility of the project. In order to assure the integrity and accessibility of the Frac String during Plug and Perf hydraulic fracturing operations of one of the toughest rock in Unconventional business worldwide, one procedure has been developed for running operations best practices. Pressure testing the Frac String (FS) during running in hole in stages while in vertical section to sure safe and successful Wireline setting and retrieving nipples plug with more than 30% solids in the system (high mud weight) to guarantee no leak in the string prior reaching total depth (TD). Hanging and testing cross over (XO), assuring compatibility with the wellhead connections. Cementing up to18.7 ppg. Flexible and expandable slurries, cement inside previous casing and apply pressure on surface to avoid gas percolation during the cement setting period. Cleaning out with Coiled tubing (CT) to ensure no obstruction and using different completion fluids for future accessibility. And finally, Pressure testing the Frac string up to 14ksi all are new practices and proven mitigation measures for all assessed risks for hydraulic fracturing operations. This paper is about sharing this new procedure in Abu Dhabi for having a cemented FS in UC wells High Pressure / High Temperature (HP/HT) with 100% integrity and internal accessibility to run plugs, perforations, logs and be able to apply high surface pressure to frac the tight reservoir in the planned zone, creating the desired permeability for future production.

Abstract Hydraulic fracture design driven by multi-disciplinary collaboration can maximize the production potential of complex multi-frac horizontal wells. Integration of multiple information sources (i.e.: geological, dynamic and geomechanical data) allows to build representative models and have proven to improve modelling towards a realistic understanding of tight reservoir performance of several multi-fracced wells. 3D properties encompassing the reservoir geological heterogeneity, pore pressure, mechanical elasticity and state of stress were utilized to develop a strategy to fracture stimulate a horizontal wellbore in the North Sea Region. The study was instrumental to build fit-for-purpose hydraulic fracture designs by incorporating state of stress changes related to pore pressure depletion on different faulted compartments supported by a reservoir dynamic simulation. Such models provided meaningful value to optimize the well trajectory used to access the host rock, understand fracture height growth possibilities in different compartments and define the number/size of hydraulic fractures required for optimum production.

Abstract This paper details a field application of a well-known technology for sand management (Inside Casing Gravel Pack - Frac&Pack), deployed for the first time in Eni for such a complex configuration, in a challenging environment with surface equipment limitation (jack up rig). The job has enabled exploitation of residual reserves in of a mature gas field in Adriatic Sea. This was a dual completion with two 2 3/8" production strings, producing a total of six gas bearing zones. The topmost zone produces from the short string while the rest of the zones produce through the long string. Some of the challenges were: Narrow screen-casing clearance causing increased risk of bridging and early screen out Small ID tool and workstring resulting in high friction and requiring high horsepower Limited rig space for pumping equipment All six zones were successfully executed using visco-elastic surfactant fluid formulated in 14.8ppg Calcium Bromide brine. The use of the high-density carrier fluid enabled using low horsepower equipment. The well was completed within the expected timeframe and cost with no service quality issues. The well's production has exceeded expectations. Characteristics of the field, technical issues, results and analysis are presented.

Abstract The final goal in a perforation operation is achieving the maximum production and reducing perforation damage, using optimal completion process. The Dynamic Underbalanced Perforation (DUP) as one of the more recent completion technologies minimizes or even eliminates the perforation crushed zone by optimizing the well's dynamic underbalance. Dynamic underbalance is a transient underbalance process that occurs immediately after creation of the perforation tunnels. The modeling of this process is essential in designing the optimal configuration of the perforation charges to evaluate the perforation efficiency. In this study we propose a novel and efficient numerical method, to optimize the completion efficiency which is rarely attended in the literature. There are five main steps in our modeling procedure: Calculating volume of the gas released in detonation, Calculating inner temperature of the Gun, Calculating remaining gas and energy amount inside the gun, Calculating pressure and casing stability analysis, and finally Calculating perforation skin. Although there are some computer programs that claim to model the DUP technology, none of them uses a fully numerical method. In fact, all of these programs use experimental data and correlations to predict the efficiency of this process.