With the large amount of tight gas reserves remaining in Oman, new innovative techniques and methods to unlock these reserves have become imperative for the future economic success and stability of the country. Among the various technologies considered, the concept of underbalanced coiled tubing drilling (UBCTD) was introduced. In order to address the harsh downhole challenges such as high temperatures, deep burial depths, under pressured reservoirs, abrasive and hard sands and logistical constraints; a fully integrated well delivery solution was developed jointly by the operator and energy service company. In accordance with this strategy, best in class downhole drilling tools, a state-of-the-art fully automated coiled tubing drilling unit together with technical and project management experts were deployed. Application specific solutions to the challenging subsurface conditions included utilization of underbalanced drilling (UBD) techniques, deployment of high temperature drilling assemblies, fit-for-purpose bit drive mechanism and a robust integrated management system. All of the above was achieved whilst ensuring the safety of all personnel during the project and reducing carbon emissions through a flare minimization strategy and diesel consumption reduction initiatives. Over the course of the pilot campaign, reservoir exposure per well was doubled, average penetration rate compared to conventional rotary drilling was more than tripled and incremental production improvements of up to 230% were observed. This paper discusses the challenges faced and the solutions implemented during this three well pilot campaign.

Short radius wells typically incorporate build rates between 35deg per 100ft and 70deg per 100ft. These wells are typically drilled to minimize exposure of a problematic zone above the target or to reduce geological uncertainty. This paper will discuss best practices and equipment developed specifically for delivering these wells in the Middle East. Case histories will illustrate the close collaboration with the operator resulting in performance step change for short radius drilling. The approach is based on a rigorous Drilling Engineering process. Such process is divided in four major steps; design, execute, evaluate and optimize. One of the first key steps is to perform a diligent risk assessment ensuring the customer objectives are achieved. This resulted in the development and implementation of technological innovations on downhole motors and Measurements While Drilling (MWD) tools to achieve the required high build rates safely and consistently. Proper communication was crucial for flawless execution, and meticulous documentation enabled proper evaluation and optimization of the art of short radius drilling. For over 10 years, multiple short radius wells have been consistently delivered meeting their objectives; from successful sidetracking operations, accurate curve landing, optimum geo-steering, valuable Logging While Drilling (LWD) data collection, to extending the life of the wells by maximizing their production. The last two steps of the Drilling Engineering cycle (evaluate and optimize) have been the foundation of the continuous improvement process; targeting adequate equipment maintenance, Bottom Hole Assembly (BHA) design and operational practices to ensure consistent results. The paper will recap the drilling engineering cycle for wells drilled recently. The discussed best practices have enabled master the art of short radius drilling. Such distinctive knowledge should be shared with the entire oil and gas industry. The paper captures the engineering approach to tackle the traditional challenges of drilling short radius wells. It also discusses the reliable solution for drilling short radius wells in Middle East which are planned to access new reserves from an existing infrastructure, while minimizing drilling and geological risks.

In workover phase prior to commencing sidetrack operation, it is required to recover old existing completion string for isolating & abandoning existing reservoir section in accordance with well integrity and global well abandonment standards. Prior to utilization of the coiled tubing cementing approach, the practice was to recover all existing completion by cutting and pulling out the dual tubing or mill the permanent packer. After all the completion recovery, spot and squeeze cementing operations were conducted. However a major drawback of this process is, until recovering some part of completion string, the actual physical condition of the completion strings remains unknown and it poses high risk to get stuck in cased hole or end up in loosing accessibility inside completion string due to corrosion. Furthermore, in some of the old wells had failure to recover completion components like a dual flow assembly and a dual packer due to completion age, had led to improper zonal isolation. Even if all the old existing completion is recovered successfully, it consumes a lot of operation time and several fishing trips with overshot or junk mill BHA (Bottom Hole Assembly). In order to minimize the risk of being stuck or loosing accessibility and ending up failing to recover existing completion and to save operational time, the coiled tubing cementing was conducted to isolate existing reservoir and leave remaining parts of completion downhole. During the operation phase, injectivity test was performed by pumping sea water followed by bull heading kill fluid in to the reservoir. Losses rate was evaluated while observing the well, a high viscosity pill was spotted in order to treat losses and control loss rate. Coiled tubing was rigged up on Long string and run in hole to tag a landing nipple in existing completion string in order to have reference of depth corrected against ORTE (Original Rotary Table Elevation) depths while using the coiled tubing for operations. After having correct reference of depth with tagging completions nipple accessory, coiled tubing with slim OD cementing BHA was run in hole to tag PBTD (Plug Back Total Depth) and then picked up to certain depth while spotting cement slurry at controlled speed. Once the complete amount of slurry was spotted during picking up coiled tubing was pulled out to be away from cement slurry and then coiled tubing BOP (Blow Out Preventer) was closed and cement was squeezed in to the formation. After squeezing pre determined volume or archiving the lock up pressure, coiled tubing was pulled further up and circulated out to ensure all cement slurry out from coiled tubing (inside and outside). Top of cement was confirmed by tagging with the milling assembly connected to coiled tubing and the pressure test was performed after waiting on cement to confirm the integrity of the barrier. For short string, similar abandonment plug process was followed as that of the long string. After performing tagging operations, cement was spotted while pulling out the coil tubing to certain depth and then coil tubing was picked up above the cement to squeeze cement in to the formation. Similar coiled tubing cement operation for isolating lower perforations was performed on three other wells, and proper zonal isolation was achieved against reservoirs. This improved approach of abandoning lower reservoir prior to completions recovery proved to save 2-3 days of rig operational time in comparison to previous operations practices of recovering existing completion completely & then perform cementing operations for zonal isolation against each reservoir. Based on the successful result in three wells, it is concluded that this coiled tubing cement operation is effective for zonal isolation and provide savings in operation days.

Drilling long laterals within Shuaiba limestone reservoir without exit to Nahr-Umar shale in the challenging field "B" that is characterized by geological uncertainty can have major risks. The low to very low resistivity environment reservoirs are common in Oman especially while placing wells nearby OWC; on a reservoir spot window of 1-2m TVD only. The main objective is to place the well less than 1m TVD below the reservoir top, this was achieved by utilizing Multilayer Bed Boundary Detection and Rotary Steerable System. Integrating propagation resistivity curves response with the directional resistivity curves response from Bed Boundary detection tool have been used as a guide for an optimal well placement in low resistivity reservoir, along with Rotary Steerable System are one of the best strategies which have been used to place the wells within the right spot. For tight geosteering window with an aggressive formation tendency pushing the azimuth left or right and continues inclination instability associated with the existence of an interbedded layers of hard streaks within the reservoir, a faster and more competent Rotary Steerable System tool and Bit selection is required, as proven it provides better stability results for achieving well placement objectives and respond in fast manner to geosteer in real time. The objective of this paper is to describe the geosteering logging while drilling (LWD) technology and technique and Rotary Steerable system (RSS).

Drilling horizontal wells with a high dogleg severity (DLS) of 10–16 deg/30 m is the approach that one operator in Oman adopted to drill the buildup section. The 8½-in section used to be drilled with a conventional motor BHA, which took around 4 days to complete. Due to the high DLS, it was required to slide at least 80% of the time. This led to a slow drilling rate, hole cleaning issues, and difficulties running the 7-in liner afterward. For a step change to happen, a full directional drilling system had to be reengineered with an extensive study of the BHA and well design. The objective was to reduce the total drilling time in the 8½-in BUS, improve the borehole quality, and reduce flat time. Traditional rotary steerable systems (RSS) are limited with their steering capabilities. A hybrid, high-build-rate RSS with push- and point-the-bit features offers the capabilities of achieving a DLS of up to 17 deg/30 m as it is independent of outside formation. Implementing the new approach eliminated the long sliding intervals and poor borehole cleaning caused by limited surface rotation with the motor BHA. The system was modeled using finite element drilling dynamics simulation software, with multiple bits and drillstring configurations to optimize the directional results. In addition, compressive study of the mud properties enabled drilling the section safely throughout Nahr Umar shale. Later, the same system was coupled with a high-torque motor, and the results showed an even better performance, which the operator plans to consider in the future to enhance the drilling rate. The use of a hybrid RSS system with a specific bit built for the application has proven its success as an integrated engineered drilling solution. It reduced the 8½-in section drilling time by 50% with improved borehole quality and delivered an overall ROP that is approximately three times what a motor BHA would have delivered. The improvement is a result of the use of PDC over TCI bits and the elimination of slide drilling. In addition, full rotation and elimination of micro-DLS resulted in smoother liner running operation. While drilling, the 100% rotational steering improved the overall hole cleaning, and the modified mud properties and additives helped eliminate the wiper trips performed previously prior to reaching the reservoir section. The success of this integrated system led the operator to replace all the motors in the entire field. This paper emphasizes the impact of new technology together with effective well engineering in drilling efficiency. With current industry focus on cost control, high-DLS RSS technology introduces new savings when used in the right application. This particular case is very common across the industry and proves the many advantages of integrated engineering projects.

Drilling horizontal wells in the mature giant carbonate fields offshore Abu Dhabi, where high uncertainty regarding the lateral distribution of fluids results in variable water saturation, is very challenging. In order to meet the challenges and reduce uncertainty, the plan was to drill pilot holes to evaluate the resistivity of the target zones and plan horizontal sections based on the information gained. To investigate the possibility of avoiding pilot holes in the future, an ultra-deep electromagnetic (EM) tool was deployed to map the mature reservoirs, identifying formation and fluid boundaries before penetrating them, avoiding the need for pilot holes. Prewell inversion modeling was conducted to optimize the spacing and firing frequency selection and to facilitate early real-time geosteering and geostopping decisions. The plan was to run the ultra-deep resistivity mapping tool in conjunction with shallow propagation resistivity, density, and neutron porosity while drilling the 8 ½-in. landing section. The real-time ultra-deep EM inversion was run using depth of inversions up to 120 ft., to be able to detect the reservoir early and evaluate the predicted reservoir resistivity. This would allow optimization of any geostopping decision. The ultra-deep EM tool delivered accurate mapping of thin reservoir layers while drilling the 8 ½ inch section, as well as enhanced mapping of low resistivity zones up to 85 ft. True Vertical Thickness (TVT) in a challenging low resistivity environment. The real-time EM inversion enabled the prediction of resistivity values in target zones prior to entering the reservoir; values were later crosschecked against open-hole logs for validation. The results enabled identification of the optimal geostopping point in the 8 ½-in. section, enabling up to seven rig days to be saved in the future by eliminating pilot holes, in addition to eliminating the risk of setting a whipstock at high inclination with subsequent milling operations. In specific cases, this minimizes drilling risks in unknown/high reservoir pressure zones by improving early detection of a formation tops, thus improving geostopping decisions. Plans were modified for a nearby future well and the pilot-hole phase was eliminated because of the confidence provided by these results. Deployment of the ultra-deep EM tool in these mature carbonate reservoirs may reduce the uncertainty associated with fluid migration. In addition, use of the tool can facilitate precise geosteering to maintain distance from fluid boundaries in thick reservoirs. Furthermore, due to the depths of investigation possible with these tools, it will help enable the mapping of nearby reservoirs for future development. Further multi-disciplinary studies remain desirable using existing standard log data to validate the effectiveness of this concept for different fields and reservoirs.

Throughout the last few years, oil company strategies have moved toward recovery of the maximum oil in place from mature fields and reservoirs that were previously considered technically challenging. The Mauddud formation in the Bahrah field is a low permeability carbonate formation with moderate to high oil viscosity. Viscosity is between 2 and 7 cp at 170°F, but a 90-cp viscosity at surface conditions is commonly observed once a well is placed on production, creating challenges for a vertically drilled well that could not provide necessary levels of sustainable production. In an attempt to achieve economic continuous production, a 3,000-ft lateral horizontal well was drilled. The lateral length was designed as an optimal solution for such a challenging reservoir to help sustain the production flow. Additionally, a multistage acid fracturing (MSAF) treatment was performed. This paper discusses the design, execution, and production of the first MSAF treatment performed in the Mauddud reservoir using a cased openhole completion with swell packers and sliding sleeves that were placed in seven stages across the 3,000-ft lateral interval. Post-operation analysis exhibited highly sustained production, creating a shift in oil company plans toward drilling new horizontal wells and applying MSAF treatments to move the Bahrah field into the development phase. Results obtained from this operation were effectively used to help improve production in similar mature formations. Based on this pilot treatment, a wide-scale field development strategy was planned, and many wells were drilled, completed, and fractured similarly in Bahrah field.

The objective is to increase the production/injection rate of the existing old sick vertical wells that are completed with 7" casing, by extending the reservoir exposure with converting those wells to horizontal producer/injector. In the initial Field Development stage, many wells were drilled and completed with 7" casing up to the surface. Several of those old wells are lying inactive in North Kuwait which has one of the largest oil reservoirs in the country. In addition, of the limited surface locations in the field combined with the growing anti-collision challenges, feasibility studies were carried out for reviving such sick wells which can't be delivered via limited hole sections; accordingly, an innovative idea introduced to complete those wells with 3 7/8" or 4 1/8" Open Hole Completion. To address the required challenges, 2-7/8" PAC HT DP had been used along with 3 1/8" Motor. Consequently, DP had to be spaced out every trip to maximize the WOB transfer and mitigate Buckling issues. This paper provides an overview of 3 7/8" slim horizontal hole by taking the challenge to the next level by drilling the longest 3 7/8" horizontal slim hole in the world with a total footage of 4,565 ft. Total 7-runs had been performed to achieve this lateral length due to the limitation of BHA/LWD Battery life. Thirteen such wells have already been drilled consisting of 7 Injectors and 6 Producers. The Slim Wells are completed as an Injector with 5" seal assembly along with 4 ½" Tubing, or as a Producer with 3 ½" tubing and ESP. All wells (both Injectors and Producers) have yielded results commensurate to the potential of any new conventional horizontal well. Consequently, Slim Hole Horizontal wells were successfully drilled in Kuwait Oil Company fields. As such, the campaign of reviving the sick wells helped KOC to achieve higher return on investment in mature assets through minimizing top hole construction cost and time. The success has opened up new avenues for KOC. Re-entry wells helped to achieve higher return on investment in mature assets through minimizing top hole construction cost and have been drilled at 1/3rd the cost of a new well. It also accelerates time to oil production from existing wells and has minimized the prevailing location constraints. KOC has launched an aggressive plan to complete more such sick wells.

X reservoir in one of Iraq's field, is a medium pore, low permeability and small pore throat limestone oil reservoir with poor petrophysical characteristics. This reservoir group in which X reservoir is in constitutes to about 20% of the total resource in place. Conventional development allows only about 0.3% of reserves to be developed and this needed to be improved further. The mixed results of various stimulation campaigns (for example matrix acidising and acid fracturing) carried out earlier for this reservoir has prompted the Operator to evaluate the hydraulic fracturing stimulation, first of its kind in Iraq to further gauge its effectiveness and feasibility for field implementation. This paper will discuss the steps undertaken before, during and after the hydraulic fracturing execution. In planning for this campaign, steps were taken to analyse the rock properties and mechanics of the formation to understand the challenges for the hydraulic fracturing and to enable optimisation of the fracturing parameters. Fracture fluid design, proppant optimisation and treatment design were proposed to systematically optimise the process of the hydraulic fracturing. As a deduction, the principles and recommendations of design optimisation for hydraulic fracturing in carbonate reservoirs will be presented in this paper. The preliminary production gain from this pilot hydraulic fracturing exceeded the pre-job stimulation more than 10 times, showing promise of a new way of developing this challenging reservoir in the future. Comprehensive analysis of the reservoir characteristics and suitable fracturing design are key to this achievement. This approach will be the benchmark for future hydraulic fracturing jobs planned in the field. The optimisation study in this paper could serve as a reference to improve hydraulic fracturing efficiency and success in other similar carbonate reservoirs. Being the first ever hydraulic fracturing campaign ever performed in Iraq, this paper will focus on the challenges, execution and preliminary results.

Sandstone matrix acidizing is a challenge in most cases. The conventional mud acid system involving hydrochloric acid and hydrofluoric acid (HCl:HF) is widely used in stimulating sandstone formations. The disadvantage of using HCl:HF is in its rapid reaction rate, resulting in insoluble by-products from secondary and tertiary reactions that limit the treatment effectiveness. The system can also limit the acid's performance capability when deep formation stimulation is targeted. Enhancing HCL:HF acid system has been developed by utilizing of a protective ion-complexing agent. The agent forms a temporary protective film on clay surfaces allowing the acid to react with the remaining parts of the formation. The stimulation treatment fluids can be placed within the open hole reservoir section using two methods. The first utilizes 2-in. by 1-in. concentric coil tubing (CCT) with side-jetting nozzles to achieve uniform placement across the horizontal section and deep penetration inside the matrix. The second method uses a conventional bull heading treatment. Laboratory testing was performed to qualify the treatment. Different minerals were used to evaluate and understand the retardation of different acid systems. The solubility of clays was lower comparing to normal HF acid systems, indicating the slow reaction of the acid on clays and a sign that improved retardation was achieved. Further testing confirmed the formation of a protective layer on clays, enabling the acid to react more efficiently with the remaining minerals. After successful laboratory testing, field trials were conducted on four oil-producing wells in southern Oman that experienced fines migration issues. The main acid system was squeezed into the matrix, followed by brine post flush, and then flowed back. Treatments with the protective acid systems in the treated wells showed a net oil gain of 30% to 80% sustained for longer than six months. This paper outlines the technical challenges in the design and application of the proposed acid system and presents the successful lab results indicating the formation of the protective film on the clays minerals and the deep penetration phenomenon.

Intelligent Inflow tracer technology can quantify zonal inflow contribution and identify the location of water breakthrough as its' primary monitoring capabilities. A novel chemical tracer system was permanently installed and successfully field tested in a horizontal oil producer in Saudi Arabia. These intelligent tracer systems allows the monitoring of the entire length of the production section, as early as the clean-up phase. They can also continuous production monitoring for up to ten years without the need for intervention. Some of the lesser known monitoring possibilities include inflow control valve actuation monitoring, packer integrity, multi-lateral and zonal inflow conformance. Understanding fluid influx profiles through permanent interventionless surveillance, has facilitated clean-up operations and improved long-term well performance, as presented in this paper. Unique oil and water soluble tracers are embedded in solid polymeric substrates and mounted on specialized carrier subs in each reservoir compartment separated by packers. When oil or water contacts the polymer substrates, the respective tracer is diffused out gradually with time. Produced fluid samples are collected at surface and analyzed for the presence of unique chemical tracers. The tracers can be measured down to parts per trillion (PPT), using advanced liquid chromatography coupled with a mass spectrometer. The presence and relative contribution of oil and/or water can then be determined for each downhole compartment in the reservoir. This inflow tracer technology was field tested in a 3000ft horizontal well, penetrating a carbonate reservoir. The openhole section was segmented into five compartments using packers which was also equipped with inflow control devices (ICD) integrated with sliding sleeves. Oil and water tracer carrier subs were placed in each of the five compartments. Initial surface sampling of first production showed water tracers from each of the five compartments, as expected with flowback of the completion brine. After clean-up the well produced 100% oil, and surface sampling indicated contribution from only the two heel compartments. The surface choke was opened to very high rate in an effort to clean-up the toe compartments. Subsequent surface sampling confirmed production from additional compartments many months after the cleanup but not from the toe. Periodic surface sampling has continued for nearly two years and will continue for the remaining tracer longevity. The tracers have been instrumental in pinpointing the location of water breakthrough and determining appropriate corrective intervention. In case of high water cut in any compartment, the offending segment(s) can be retarded by the closure of the sliding sleeve ICDs. The application of this wireless surveillance technology is a cost effective means for optimizing horizontal well performance, particularly in mature reservoirs and most appropriate for extended reach wells to overcome the limitations of PLTs and fiber optic monitoring solutions ( Semikin et. Al, 2015 ).

The horizontal wells are applied to enhance the production rate by increasing the contact area between the wellbore and reservoir, it has been also used to access the highly heterogeneous and unconventional formations. One horizontal well can produce the same amount of 5 vertical wells with a very competitive cost and operational time. Further improvement for the productivity of horizontal well can be achieved by conducting hydraulic fracture operations, especially for low permeable or unconventional formations. This paper shows a new technique to estimate the performance of hydraulically fractured horizontal wells, without a need for using downhole valves or smart completion. In the literature, few empirical models have been proposed to evaluate the inflow performance of such wells. However, most of these models assume constant pressure drop in the horizontal section, therefore, significant errors were reported from those models. In this work, a reliable model will be presented to predict the well deliverability for hydraulically fractured horizontal well producing from heterogeneous and anisotropic formation. Different artificial intelligence (AI) methods were investigated to evaluate the well performance using a wide range of reservoir/wellbore conditions. The significant of several parameters on the well productivity were investigated including; permeability ratio (k h /k v ), number of fracture stages and the length of horizontal section. The AI model was developed and validated using more than 300 data sets. Artificial neural network (ANN) model is built to determine the production rate with an acceptable error of 8.4%. The model requires the wellbore configurations and reservoir parameters to quantify the flow rate. No numerical approaches or downhole well completions were involved in this ANN model, which reduce the running time by avoiding such complexity. Moreover, a mathematical relation was extracted from the optimized artificial neural network model. In conclusion, this work would afford an effective tool to determine the performance of complex wells, and reduce the differences between the actual production data and the outputs of commercial well performance software.

The Middle East has long been a pioneer in innovation in drilling and completion technologies for multilateral wells. It was here that the first 1 multilateral tool (MLT) on coiled tubing was used to access and stimulate each openhole lateral in a trilateral well. Over the years, several 2 - 4 applications of this and similar technologies have been made. In each instance, a conventional upper completion system was installed. In a multilateral well with a conventional upper completion and an openhole lower completion, there is no independent flow control from each lateral. Because of this, production is not optimized to account for differences in the production rate or reservoir quality of each lateral. For a well with an upper intelligent completion system (ICS), independent control of flow from each lateral is possible through the use of surface controlled flow control valves (FCVs). This feature addresses the shortcomings of the conventional upper completion mentioned earlier. The challenge in performing an acid stimulation of each openhole lateral in a well with an ICS is the inability to access any of the laterals after the ICS has been installed. Current technologies do not afford this option and designs in the pipeline do not have field proven applications. This paper chronicles a novel attempt at acid stimulating each openhole lateral of a trilateral well in a carbonate reservoir. It includes the installation of the ICS in the same well. The challenges, results, learnings and future courses of action are documented in what should provide a template for continuous improvement.

Rhourde Attar field in the northwestern Algerian desert is exploited from the Lower Devonian sandstone. This formation is composed of sandy and silty-sandy intervals with thin, shaly intercalations. The reservoir is characterized by very porous sands (20 to 25%), which also show relatively low permeability (1 to 15 md). Deposition of chamosite minerals reduced permeability, without reducing primary porous volume. This paper proposes a pillar fracturing technique designed to overcome formation constraints and enhance production. Beyond the moderate petrophysical properties related to rock diagenetic history, the reservoir is suffering from a gradual depletion trend, limiting the oil production rate and driving the bottomhole operating condition below the bubble point. It was proposed that placing a highly conductive fracture stimulation treatment could possibly help overcome these constraints. An oil producer well of the field was selected for the first application of a pillar fracturing technique combined with a resin to consolidate the created channels within the fracture. The pillar fracturing technique allows conductivity maximization through the placement of open channels within the stabilized proppant pillars. This unique fracture geometry is achieved by pulsing clean fracturing fluid stages alternated with slurry stages that carry the propping agent. The proppant pillars are then stabilized with the addition of a specifically designed resin to coat the proppant as it was being pumped throughout the entire fracturing process. Proper candidate selection, accurate fracture modeling, and employment of proven pumping equipment are crucial elements for achieving a successful and safe intervention. The implementation of this stimulation technique provided positive results both in terms of operational execution and final well performance. Additionally, this technique mitigates the risk of undesired screenout by reducing the proppant volume compared to a conventional job. Moreover, the initial production of the well revealed a significant improvement while the long-term performance showed a stabilized trend. Based on these outcomes, the use of this technique could face a fast increase within the Algerian market, considering also possible refracturing interventions on older wells.

In global underbalanced drilling (UBD) applications, the main contributing factor for downhole fires is often attributed to the use of air as the primary gaseous phase in the reservoir interval. The industry has adopted a general practice to avoid using air in UBD operations in the presence of hydrocarbons. This paper challenges this paradigm by discussing the planning and application of a successful air-foam UBD application in Australia to drill a low-pressure, highly depleted, gas-bearing reservoir. By using air as the primary fluid medium and eliminating the need for membrane-produced nitrogen, the UBD cost was reduced by 25% and reservoir deliverability exceeded the production expectations. This paper discusses the risk mitigations, modeling, and technical justification applied to the challenging project to demonstrate that even when inert gases may be the recommended choice, air can be used safely in some cases to optimize operational efficiency and cost.

Though extended reach completion has become more common in Abu Dhabi and the region, there are still challenges to overcome in completing of the lower completion in order to have better control on production, injection and stimulation, especially, when the reservoir characteristics vary along the lateral. Multiple horizontal wells with different lower completion design have been drilled and completed in the region, e.g. Pre-Perforated Liner (PPL), Limited Entry Liner (LEL), Inflow Control Device (ICD's) & Inflow Control Valve's (ICVs). All of these laterals have been designed to have multiple compartments with certain separation in order to control the stimulation job either by bullheading (pumping from surface) and/or using coiled tubing (acid wash). All these designs have limitations in either the control or in the number of compartments. Particularly, when early water breakthrough in the producer wells, PPL/LEL are effective, ICD completed wells are not the best for the stimulation jobs, while the ICV completed wells have a restriction in the number of compartments, high temperature wells and liner running. This paper is to share not only the knowledge but also the complete well design of the Sliding Sleeve Valves (SSVs) lower completion along with the upper completion design and to illustrate how the design will add value to the field development.

Drilling, completing, and the production monitoring and control of multilateral wellbores in highly unconsolidated sandstone formations have achieved technical and operational success in recent past by ensuring that economic viability is attained and that well life is prolonged. Gravel packing the lateral branch on a multilateral well is no longer a challenge. Sound isolation of the main branch is achieved to preserve the mainbore of debris when milling the window and drilling the lateral, which will ensure seamless gravel-pack operations. Stable junction isolation exists to support sand placement and the subsequent reverse-out of gravel-pack operations in both the main and lateral branch. Additionally, it is no longer considered a risk to run long, stiff, bottomhole completion assemblies across the window junction. One of the key factors in determining if a multilateral wellbore might be suitable for a given project is the type of sand-control completion and technique that might be required. The use of conventional standalone screens has a long and highly successful history. And now, where more sand-control reliability is required via use of gravel packs in combination with multilateral wellbores, technology is available and is also beginning to develop its own successful history. Multiple successful installations of dual-bore, horizontal gravel-pack completions combined with Level-5 multilateral completion systems has resulted in increased reservoir drainage to improve the oil-recovery factor as well as the economic gains. In its current, form when combining advanced sandface completions with multilateral completions, the gravel-pack operations are followed by the installation of multilateral and upper completions. As a result of a newly developed system, one can now interconnect the junction completion with the sand-control operations in a single, seamless operation.

Challenges of oil recovery in mature assets continue to increase, requiring horizontal wells to be drilled for longer intervals. To improve the overall production in Kuwait, horizontal injector wells are required in some carbonate reservoirs in north Kuwait fields with the main objective of driving reservoir pressure in cases where aquifers cannot contribute to sustained oil recovery. Drilling several injector wells with long lateral sections was found to be the best approach to improve reservoir sweeping efficiency and drive the pressure regime for sustaining higher production levels. Historically, all horizontal wells drilled in similar reservoirs utilized oil-based mud (OBM), which was instrumental in reducing torque and friction along the lateral sections. Recently, all injector wells in the area were switched to water-based mud (WBM) systems in the lateral to reduce reservoir damage and improve injectivity and to enable the use of microimaging logging tools while drilling. This switch, together with limited drilling rig capability and geological uncertainty, posed major challenges on the deliverability of the horizontal section to planned total depth (TD). The operator, in collaboration with the drilling services provider and other service providers, completed a substantial planning phase to optimize the well design and make it achievable using current resources. The bottomhole assembly (BHA) was modeled, with iterations made to enhance the capability of drilling long laterals with proper weight transfer without sacrificing well stability or directional control. To overcome the challenge of drilling the long lateral section without the need for intermediate trips, the tool string design was customized for additional robustness and durability. Completed in two runs, the 6979 ft section was considered to be the longest lateral in north Kuwait ever achieved at the time. Maintaining the well in the desired trajectory, the motorized rotary steerable system was used to achieve a rate of penetration (ROP) improvement above the field average and within the allowable torque limit permitted, reaching the required total depth successfully. The bit and BHA selection and design were both critical to success. The subject reservoir known for high rock stresses and varying local formation dip angles posed a challenge to maintain the well on the desired trajectory due to unpredictable changes in the BHA tendency. Rotary steerable system (RSS) automation through the use of closed loop and cruise control features helped minimize human intervention. These features enable the RSS to automatically react and change downhole settings to track target inclination. This paper discusses the planning, design and execution of the subject well, in addition to the added value and resulting improvement in reservoir sweeping efficiency.

Nowadays, the fiber has become the most important oilfield chemical material with great advantages in hydraulic fracturing treatment when considering fluid leak off, proppant transportation and fracture damage in tight oil and gas reservoirs. However, it still has some drawbacks, such as mechanical properties, heat denaturation and poor chemical stability, always emerge in oilfield cases. Accordingly, a new type of oil soluble temporary diverting agent is used to overcome these shortcomings in our research. We developed into a new agent with different types of petroleum resin and hydrocarbon resin. A series of evaluation experiment was carried out including temperature compatibility, diverting efficiency and dispersity etc. The results showed that with increasing temperature and prolonging dissolved time, the oil soluble rate of temporary agent in 6 hrs was 95%-99% at 80-120 °C, which indicated good oil solubility. After complete dissolution, the viscosity of 5-20 g/L solution was 12.6-53.7 mPa.s, which had good flowback after treatment. Furthermore, by reducing the diverting particle size and improving the level of aggregation of particles, a specially designed instrument was put forward to evaluate the performances of fracture conductivity, fracture diverting. The length and concentration of the agent were optimized in this study. More than 20 treatments with new agents in Huabei oil field have been performed with encouraging results, 95.2% efficiency with an average post-fracturing rate reach to 21.3m 3 /d, which was three times of before stimulation. The results have great influences on both theoretical study and field treatments of new chemical material for impoving complex fracure degree of hydraulic fracturing in tight oil and gas reservoirs.

This paper describes the evolution of Open Hole (OH) Multi-Stage Fracture (MSF) completions that have been deployed in the Saudi Arabian tight gas carbonate reservoirs for the past several years. The carbonate reservoir in Saudi Arabia is often highly stressed and heterogeneous and fracturing treatment response can vary significantly between stages across the same reservoir. This paper also defines the best drilling and deployment practices of OH MSF completion with swellable packers, diagnostic technique of OH packer's integrity, acid fracturing strategies, and well performance of Saudi Arabian carbonate gas reservoirs. It is important to drill in the minimum stress direction so that transverse fractures can be induced. The swellable packers are to be set across good gauged section with optimum spacing between packers and fracture ports. The stimulation treatment designs need to be tailored with optimum fluid volume after evaluating the status of packer integrity between each acid fracturing treatment. Maintaining OH packer integrity between acid fracturing stages has become the most prevailing concern in emerging independent hydraulic fractures. Evident hydraulic communication between the stages through OH packers can develop a single dominant fracture affecting the well's sustainable gas rate as well as the recovery of final cumulative gas. The loss of annular isolation during fracturing with reactive fluids is often unavoidable in the presence of severe washout and unfavorable location of packers and fracture ports. Drilling in the minimum stress direction, inclusion of swellable packers, scrutinized depth selection of packers and fracture ports, dynamic evaluation of packer integrity between injections, detailed after-closure analysis, and vibrant optimization of acid stimulation treatments have increased effectiveness of acid stimulation and enhanced production. Even though fracturing treatments in low permeability oil and gas bearing sandstone formations are routinely executed in North America through OH Multi-Stage Fracturing completion to maximize stimulated reservoir volume, but it is not as common completion technique during acid fracturing treatments in the Carbonate gas reservoirs. This paper highlights unique challenges and recommendations for acid fracturing treatments in carbonate reservoirs through OH MSF completion.