A Solution to Sand Production from Natural Gas Hydrate Deposits with Radial Wells: Combined Gravel Packing and Sand Screen

Sand production is one of the main problems restricting the safe, efficient and sustainable exploitation of marine natural gas hydrate. To explore the sand-control effects of gravel packing, experiments that simulate hydrate extraction in the water-rich environment were conducted with designed hydrate synthesis and exploitation devices. Three sand control completion methods, including 120 mesh sand screen, 400 mesh sand screen, 120 mesh sand screen combined with gravel packing, are adopted. Sand and gas production rates were compared under different well types and sand control completion methods. Results show that the gas production modes of radial wells and vertical wells are almost the same at the same time due to the small experimental scale and high permeability. The sand production of the vertical well with gravel packing combined with a sand-control screen is 50% lower than that of the vertical well with sand-control screens only. Radial well with gravel packing combined with sand-control screens produced 87% less sand than screen mesh alone. The cumulative gas production and recovery rates of a radial well with the composite sand control method are better than those without gravel packing in the same development time.

Sand Control Technology for Low pressure Lost-Circulation Wells and Application in South Sudan

A kind of plugging proppants was developed for solving the problem of ‘easy to lose sand’, resulting in difficult sand control in low pressure lost-circulation wells in South Sudan Oilfield. The proppants can cement together to form a consolidated body with certain strength (≥2 MPa) and permeability (≥1.3 μm2) in oil layers. The body can temporarily plug lost circulation channels. Meanwhile, a supporting sand-adding tool was developed to simplify the proppants squeezed process, and a sand-carrying fluid was optimized to improve sand suspension performance and protect pay zones in low pressure lost-circulation wells. These measures formed a sand control technology for low pressure lost-circulation wells. 12 wells have been successfully applied in South Sudan Oilfield and achieved good effect on increasing oil production by 15 t/d.

A Successful Application of Continuous Pack-Off Technology to Water Shutoff Recompletion for High-WCT Gravel-Packed Horizontal Well

Objectives/Scope Controlling the excessive water production from the high water cut gravel packing horizontal well is a challenge. The approach which uses regular packers or packers with ICD screens to control the unwanted water does not function well. This is mainly because of the length limitation of packers which will make the axial flow resistance insufficient. Methods, Procedures, Process In this paper, a successful case that unwanted water is shutoff by using continuous pack-off particles with ICD screens (CPI) in the whole horizontal section in an offshore oilfield of Bohai bay is presented. The reservoir of this case is the bottom-water high viscosity reservoir. The process is to run 2 3/8" ICD screen string into the 4" screen string originally in place, then to pump the pack-off particles into the annulus between the two screens, and finally form the 360m tightly compacted continuous pack-off particle ring. Results, Observations, Conclusions The methodology behind the process is that the 2-3/8" ICD screens limit the flow rate into the pipes as well as the continuous pack-off particle ring together with the gravel ring outside the original 4" screens to prevent the water channeling into the oil zone along the horizontal section. This is the first time this process is applied in a high water cut gravel packed horizontal well. After the treatment, the water rate decreased from 6856BPD to 836.6BPD, the oil rate increased from 44BPD to 276.8BPD. In addition, the duration of this performance continued a half year until March 21, 2020. Novel/Additive Information The key of this technology is to control the unwanted water by using the continuous pack-off particles instead of the parkers, which will bring 5 advantages, a) higher efficiency in utilizing the production interval; b) no need to find the water source and then fix it; c) the better ability to limit the axial flow; d) effective to multi-WBT (water break though) points and potential WBT points; e) more flexible for further workover. The technology of this successful water preventing case can be reference to other similar high water cut gravel packed wells. Also, it has been proved that the well completion approach of using CPI can have good water shutoff and oil incremental result. Considering the experiences of historical applications, CPI which features good sand control, water shutoff and anti-clogging is a big progress compared to the current completion technologies.

An Investigation into Current Sand Control Methodologies Taking into Account Geomechanical, Field and Laboratory Data Analysis

Sand production is one of the major issues in the development of reservoirs in poorly cemented rocks. Geomechanical modeling gives us an opportunity to calculate the reservoir stress state, a major parameter that determines the stable pressure required in the bottomhole formation zone to prevent sand production, decrease the likelihood of a well collapse and address other important challenges. Field data regarding the influence of water cut, bottomhole pressure and fluid flow rate on the amount of sand produced was compiled and analyzed. Geomechanical stress-state models and Llade’s criterion were constructed and applied to confirm the high likelihood of sanding in future wells using the Mohr–Coulomb and Mogi–Coulomb prototypes. In many applications, the destruction of the bottomhole zone cannot be solved using well mode operations. In such cases, it is necessary to perform sand retention or prepack tests in order to choose the most appropriate technology. The authors of this paper conducted a series of laboratory prepack tests and it was found that sanding is quite a dynamic process and that the most significant sand production occurs in the early stages of well operation. With time, the amount of produced sand decreases greatly—up to 20 times following the production of 6 pore volumes. Finally, the authors formulated a methodological approach to sand-free oil production.

Extending ESP Run Life By Reducing Shutdowns and Improving Restarts Using Novel Pump Protection Technology

Meeting the production demand in today's market without sacrificing performance of the artificial lift method is critical. Aggressive flowback procedures lead to solids production and unplanned electric submersible pump (ESP) shutdowns because of solids overload. A novel pump protection system has been designed, tested, and installed in the field. The system enhances the ESP life, improves restarts, and reduces downhole vibrations and unplanned shutdown by controlling the solids flowback and sending solids-buildup pressure signals. A comparative study on three ESP wells in the Delaware basin (US) demonstrated the efficacy of the system. The system comprises of an intake sand control screen and valve assembly. The novel stainless steel wool screen acts as a three dimensional (3D) filter capable of filtering out particles of 15 to 600 μm, and the valve assembly activated by differential pressure across the screen creates a secondary flow path to allow cyclic cleanup of the screen. Stainless steel wool screen with variable pore sizes is used as the sand control media for its high efficiency in preventing the flow of most of the solid particles. When the solids build up on the screen surface, the valve assembly opens upon reaching a preset differential pressure to enable flow past the screens and into the ESP and allows sands deposited on the screen surface to fall off. The pump protection assembly was tested at surface and installed in three wells along with downhole ESP gauges measuring pressure, temperature and vibrations after pulling out existing ESP completions. Qualification testing confirmed the opening of the valve assembly after solids buildup on the stainless steel wool screen. It also validated that the deposited sand fell-off from the screen surface after flow diverted through the valve assembly and pressure differential across screen dropped. In the field installations, the run life of the ESPs improved by an average of 35%, with comparable production volumes and slow drawdowns. In addition, the number of ESP shutdowns related to sand and solids was reduced by as much as 75%, improving longevity of electrical components. The success rate of ESP startups after planned and unplanned shutdowns also improved by 22%. The increase in inlet pressure captured via the downhole gauges when the valve assembly opened indicated the sand control prevention and mitigation system was bridged, and ESP replacement should be scheduled to minimize deferred production from a solids-induced ESP failure and to minimize surface solids management costs. The vibration signal data obtained from downhole sensors confirmed the reliability of the system. Overall, results demonstrate that the system designed is successful at increasing ESP run life without detriment to well production performance. The new, field-proven pump protection system along with its components and the completion design substantially increase life of ESP by reducing the number of shutdowns related to sand overload, reducing shutdowns, reducing overall vibrations, increasing the probability of successful start after shut-in, and increasing the performance reliability during fracturing of a neighboring well. Consequently, more wells that are looking to increase the ESP life can now benefit from this technology and increase output.

20 Years of Horizontal Multistage Completions: A Summary of Industry Evolution in Unconventional and Conventional Plays

In the past two decades, the advent of the Shale Gas Revolution (SGR) was made possible by the visionary idea that hydrocarbons contained in ultra-low permeability source rocks could be extracted using available technology. Usually, these hydrocarbons take geological time to migrate to higher permeability reservoir rocks until the right structural conditions evolve to extract as recoverable resources. However, paradigm shifts in drilling and completion engineering have enabled unlocking resources from these ultra-tight formations. The innovative idea at the base of this industrial revolution was the combination of horizontal well drilling and hydraulic fracturing, which allowed increasing the surface area available for hydrocarbon flow and overcame the slow and shallow hydrocarbon release from the source rock. This approach can be considered as a bridge between petroleum engineering based on radial diffusivity equation and mining engineering based on physically accessing and extracting the resource. To achieve the high number of hydraulic fractures needed for economical production, different execution techniques evolved and developed in what is known as horizontal multistage fracturing (HMSF) completions. Although HMSF is indescribably linked to SGR, it was surprisingly applied in tight gas formation and offshore sand control applications more than 30 or 40 years ago. SGR contributed to the fast development of new innovative systems engineered and deployed at scale all over North America land operations and was subsequently exported internationally in conventional, unconventional, land, and offshore applications. This paper will cover the most common HMSF completion systems types with a primary focus on unconventionals. It will encompass the evolution of these systems over the past several decades. It will also explore the opportunity case for conventional, and high permeability plays through a series of theoretical and real examples.

Value of Managing the Subsurface Risks and Uncertainties in the Project Execution; A Successful Case History in Merakes Green Gas Field Development

Implementing a proactive approach with comprehensive reservoir characterization, risks identification and mitigation are key elements that have to be deeply investigated before the project execution for achieving the optimum results in field development. A tremendous result on the seismic driven field development and synergy with a fast track development concept in Merakes green gas field has been achieved. In this paper, the conceptual and methodologies are described in the way of managing the subsurface risks and uncertainties during the planning and execution phase. A suitable example in Merakes field development which classified as "appraisal while developing", since the remaining risks still exist during development campaign, is presented. By having only two exploration wells with limited data, a robust upfront reservoir characterization and modeling were quite challenging to provide a reliable image of the subsurface condition. The enhancement on the way of constructing an integrated reservoir study prior to the field development is considered an essential requirement that has to be done before the project execution. A comprehensive approach that maximizes the integration of Geology, Geophysics and Reservoir Engineering disciplines and brings out the reservoir risk quantification has been considered as a basis and strategic driver for both subsurface quantitative description and de-risking of development wells locations. Focusing on the subsurface risk criticality, the compartmentalization, rock facies quality, gas-water contact depth and sand production were considered as the main critical aspects that could impact the final success. Preserving mitigation strategies and adapting development flexibility concept have been prepared to overcome such subsurface unexpected conditions. A description of the well placement strategy which widely open to be optimized during the drilling campaign was allowed and brought benefits in mitigating the compartmentalization risk. The readiness of an adequate and comprehensive data acquisition program including log data acquisition, coring and well testing in the development wells has been prepared. Moreover, a sidetrack contingency plan has been also considered for a key-well in case of worse than expected results. With know-how and experiences on the nearby field development, an extensive evaluation of water and sand production risks was derisked by selecting smart completion and sand control technologies. A holistic integration between subsurface, drilling, petroleum, facilities disciplines is considered of paramount importance in development projects. The awareness of the field's risks and uncertainties allows maximizing efforts in following up the drilling phase promptly adapting the data acquisition plan to the effective level of residual uncertainty and related development risk. Eventually the good match between the expected scenario and the actual well results allowed to cancel most of the costly data acquisition plans which contributed to a positive impact on the project cost and time-saving.

Evaluation and Optimization of a Newly Developed Chemical for Sand Consolidation: HTHP Gas Wells

Sand production is a common problem in wells completed in unconsolidated or poorly consolidated formation. Several problems are associated with sand production including erosion damage, and plugging of the well and surface production equipment, such as lines, valves, etc. Various mechanical solutions have been implemented to control or eliminate sand production. Screenless completion is an alternative method to conventional sand control techniques. Screenless completion methodology involves sand consolidation, a field-proven technique which offers viable and effective strategies to prevent sand production throughout the life of the well. Sand production can lead to production loss through sand filling up, production tubing restrictions, etc. Consequently, the need for an effective sand control is mandatory. Sand consolidation is a promising technique due to significant advancement in chemicals development for sand control. The challenge with the chemical consolidation systems is their ability to provide the highest possible compressive strength with minimum permeability reduction. A newly developed sand consolidation system was assessed in this study for its effectiveness in both sand consolidation and retained permeability. Two techniques were investigated in preparation/conditioning of sand samples. Following the conditioning state, the sand samples were treated with equivalent amounts of the two components of the newly developed sand consolidation system (Resin-A and Resin-B). A consolidation chamber was used to cure sand under simulated downhole conditions of a temperature (300°F) and a stress of 3,000 psi. The consolidated sand sample prepared using 3 wt% KCl brine preflush was associated with a reduction in plug permeability of more than 99% with a compressive strength of 1,100 psi. In the second method, which employed a diesel preflush in the sand sample preparation step, an average permeability of 63 mD and unconfined compressive strength nearly 900 psi were obtained. The effect of temperature and flow rate on return permeability were investigate. The paper presents in detail the lab work conducted to evaluate/optimize a newly developed chemical system for sand consolidation in HT/HP gas wells.

Enhanced Thru-Tubing Ceramic Sand Screen: Performance Review from Pilot Installation in Offshore East Malaysia

Sand production remains as one of the most challenging complications in managing mature fields in Malaysia. More than half of the wells in Malaysian fields are completed with downhole primary sand control or require sand management throughout their lifetime. To further aggravate the issue, most primary sand controls installed have suffered from failure after an extended period of production. Thus, operators are often compelled to rely on thru-tubing metallic sand screens to reactivate idle sand wells. However, most metallic sand screens suffer from sustainability issue due to substantial erosion especially for those installed in wells with high gas flow rate. Therefore, alternative technology such as through-tubing ceramic sand screen (TTCSS) has been considered and applied due to its higher durability and resistance against erosion. This paper will discuss the evolution of TTCSS design and performance improvement in terms of longevity. Field application in Malaysian mature fields has shown that ceramic sand screen demonstrates a longer lifetime when compared to conventional metallic sand screen. However, to further improve the mean time between failures (MTBF) of TTCSS, extensive studies have been conducted by carrying out detailed teardown investigation and computational fluid dynamic (CFD) simulation. Design changes have been proposed and incorporated to mitigate the erosion risk at end cap area based on previous well installation. The enhanced TTCSS were then installed in the same well with high erosional velocity as pilot testing. The operating well envelope and installation method were maintained following the previous installation. TTCSS with enhanced design were then retrieved after a period of three months for detailed evaluation. Several criteria have been identified as key performance indicators for the success of enhanced TTCSS design. Throughout the pilot testing period, sand production at surface has been closely monitored to detect any sand grains larger than screen slot sizing. Upon retrieval, enhanced design of TTCSS shall not exhibit similar erosion patterns at end cap area which will affect the integrity of spring compensator system and cause the screen to lose its filtration mechanism. Lastly, enhanced TTCSS design shall prevent parting of screen during retrieval, reducing the risk of leaving the screen downhole as fish. This paper will present the outcome of pilot testing of enhanced TTCSS by comparing the performance with the original design using both teardown investigation and velocity calculation. Suggestion for further optimization will also be discussed to ensure TTCSS remains as one of the competent candidates for remedial sand control which can offer greater durability and longevity.