Sand Control Technology Research Articles

Research and Practice of Sand Control Completion Technology Optimization in Western H Oilfield

Abstract In view of the problems of poor reservoir physical properties, high clay content, loose cementation, shallow burial, low compaction degree, low temperature in the middle and deep oil layers during the development process of unconsolidated sandstone reservoirs in the western H oilfield, the original sand control technology has poor adaptability and short sand control validity period., this paper carried out research on the optimization of sand control completion technology. In the study, a series of optimization studies were conducted, including analysis of acoustic time difference in sand producing layers, simulation of sand control formation compaction, optimization of gravel filling particle size, and sand control tools. A high-strength artificial wellbore and cyclic gravel filling sand control completion process suitable for different sand producing well conditions were developed and applied in practice. The research results and on-site practice indicate that the high-strength artificial wellbore sand control completion technology has good adaptability in low-temperature and long wellbore sand production wells; The cyclic gravel filling sand control completion technology has the advantages of simple construction, low cost, and low probability of major repairs in conventional shallow sand producing wells; The complementary advantages of the two processes effectively solve the problem of sand damage in H oilfield. Since 2021, the optimized sand control completion technology has been applied 46 times in H oilfield, with an average recovery oil production of 3.4t per well and an average effective period of over 500 days for sand control. The overall input-output ratio is 1:2.8, achieving good benefits and having high promotion and application value.

Research and Application of Chemical Sand Control without Blockage in WellBore

Abstract The main sand control methods for oil production wells in a certain Oilfield include mechanical filling sand control, artificial well bore reconstruction with coated sand, and phenolic resin sand control. Mechanical filling for sand control requires the well bore to be intact, with residual pipe columns in the well that cannot meet the testing fluid profile, and subsequent processing often requires major repairs; The construction pressure of artificial well bore is high, and the production of chemical resin sand control is significantly reduced. In order to ensure the consolidation strength, both sand control processes are under displacement operations, and the well bore above the top boundary of the perforated layer is fixed with a plug that needs to be drilled. Research on a new type of chemical sand control technology for well bore without blockage. By using biomass cellulose crystals with smaller particle size and resin in the sand fixing agent combination, the sand particles in the formation are well coated, and condensation reaction occurs to achieve the goal of sand control. The casing will not solidify to create well bore blockage, avoiding later drilling and plugging operations. The construction pressure is low, the damage to the casing is small, and it has a certain degree of selectivity. After sand control, the water content can be reduced by more than 10%. It is suitable for sand control operations in casing damage wells, casing change wells, high inclination wells, and horizontal wells, and can be used for packer construction. As of December 2023, there have been 8 on-site applications with a success rate of 100%, Average water content reduced by 13%, and a cumulative recovery of 2936 tons of oil production. This has safely and efficiently solved the sand control problem in complex well conditions.

Remedial Conformable Sand-Control Technology Deployed Offshore Colombia

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23690, “First Horizontal Deployment of Remedial Conformable Sand-Control Technology in Colombia: Qualification and Case Study,” by Suzanne Stewart, SPE, TAQA, and Jose M. Bermudez, SPE, and Camilo Mazo, Hocol, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ The challenge of remedial sand control lies in the fact that the system must pass through restrictions in the upper completion before ideally conforming to the inner diameter (ID) of the zone requiring sand control. The complete paper describes the qualification of a multilayer, open-cell matrix polymer (OCMP) system for the first horizontal deployment in an offshore gas well. The system is capable of being deployed remedially through tight tubing restrictions while providing conformant sand control in a horizontal wellbore without the need for gravel packing, making the approach particularly valuable for scenarios where surface space is limited. Background During 2006, gas Wells CH-20, CH-19, and CH-18 were originally drilled and completed in the B2 zone in the Chuchupa field offshore Colombia. Wells CH-20, CH-19, and CH-18 experienced water breakthrough from the aquifer in late 2016, 2018, and 2020, respectively. The first workover operation in these wells was performed in 2021. The aim was to isolate the B2 zone with a packer and to perforate the slightly shallower B1 zone to access attic gas. In Well CH-18, an inflatable packer between Zones B2 and B1 was installed successfully, resulting in the ability to produce at full potential, while Wells CH-19 and CH-20 recovered their potential partially but below the calculated target rate. A new operation for the three wells was planned in 2022 to set a mechanical packer to isolate Zone B2 and reperforate Zone B1 to increase flow area, reduce drawdown at the sandface, and diminish the risk of sand production. However, because produced sand had accumulated in front of the perforations in all wells, removing the sand and setting the mechanical packer was impossible. At present, Wells CH-19 and CH-20 are not producing and Well CH-18 is on lower-than-calculated target production. Given the production difficulties, the plan is to isolate Zone B2 successfully in all wells, clean the wells, and install effective remedial sand control with significant surface-space constraints. OCMP: Conformant Remedial Through-Tubing Sand Control The OCMP system evaluated and subsequently selected for this application consists of multiple layers of highly porous (up to 85%) and permeable (40 darcies or greater) OCMP bonded to a specially designed base pipe. The compressibility of the system enables it to be run in hole compressed within a sleeve to allow passage through tight restrictions in the upper completion; then, once in place, the sleeve can be removed, allowing a return to the original shape and conformance to the ID of the sand-producing section. The system can be run on slickline, braided line, coiled tubing, or pipe. If deployed with a hydraulic conduit, it has the capability to perform sand cleanout during deployment and can incorporate an integral hydraulic-set, high-expansion anchor. If run with slickline or braided line, it is necessary to run an anchoring device on a separate trip; then, the first OCMP system can be anchored in place.

A critical review on analysis of sand producing and sand-control technologies for oil well in oilfields

Sand production in oil wells seriously affects the production of oil and gas in oilfields. Although conventional sand-control techniques can effectively prevent sand production, it may also limit the productivity of oil wells. Fracturing and packing sand control technology changes the distribution of pressure and flow in the wellbore, while foam polymer resin diversion technology reduces the anisotropy of reservoir permeability and increases the area of oil leakage in the reservoir, both achieving the goal of sand control and increased production. The sand-free production rate is successfully increased thanks to zeta potential sand control technology, which modifies the formation’s sand potential and causes the sand to agglomerate without harming the reservoir. This article first looks into the causes of sand production in oil and gas wells before examining the fundamentals, implementation strategies, and effects of traditional sand control techniques, fracturing and filling sand control technology, foam polymer resin diversion technology, and Zeta potential sand control technology. In this article, the experience of sand control technology in actual oil field applications is summarized, explained in detail, and the future development possibilities of sand control technology are discussed.

Case Study: Innovative Sand-Screen Technology Resolves Offshore Nigeria Water-Injection Issues

_ During continuous injection, reservoir solids usually remain within the reservoir. However, prolonged or abrupt well shut ins can trigger intense transient flow phenomena like water hammer, backflow, and crossflow, causing fines and matrix sands to migrate and accumulate in the wellbore (SPE 187103). As a result, the accumulation of debris can markedly reduce structural integrity and the overall long-term viability of enhanced oil recovery (EOR) from the injection wells. This issue had become particularly evident in an offshore field situated in the southern region of the Niger Delta. Over time, buildup in the well led to a substantial decrease in injection rates, which had significantly shortened the operational lifespan of the wells to just a few years at the anticipated injection rates. Various remediation technologies were attempted, such as tubing-installed valve and backflow-restrictor technology but both proved ineffective in resolving annular-flow and crossflow issues. To prevent potentially expensive and complex interventions, sidetracking, or wellbore abandonment, further analyses by the operator, SNEPCo, concluded that an effective solution necessitated deployment as close to the sandface within the injector wells as possible. The Cascade system, a check-valve system developed by TAQA Well Completions (formerly Tendeka), was then successfully deployed in three wells to maintain the required injection volumes for efficient pressure maintenance and reservoir sweep. Non-Return Valve Screen Technology Establishing a reliable flow-control system for the lower completion requires engineering the check-valve components to seamlessly integrate within the sand-control screens for deployment across multiple zones of the injection tubing. The non-return valve (NRV) employs a three-component design comprising a valve body, valve insert, and ball. Ball check valves are installed on the screen base pipe under a shroud that allows the injection of fluid into the reservoir and prevents any backflow from the reservoir during shut ins. The system features a flow-control check valve integrated within traditional sand screens that do not alter completion geometry (Fig. 1). With a metal-to-metal seal, it essentially isolates fluid in the completion annulus and locks injection water into the formation. The NRV has been designed to handle a variety of well conditions including erosion, plugging, temperature, and repeated checking cycles. All flow-control device components are manufactured with high-alloy stainless steel and tungsten carbide components to resist tortuous downhole conditions for up to 15 years. Developed in 2018, more than 2,000 of the valves have already been successfully installed in several wells globally. As this new sand-control technology can autonomously and immediately isolate the reservoir from the wellbore during shut ins, the technology offers additional benefits. - Nonintrusive nature for intervention tools - Unhindered access to the lower completion sandface during injection and intervention - Durability throughout the well’s operational life - Compatibility with openhole standalone screens, gravel- pack completions, direct wrap or metal mesh screens - Cost-effectiveness compared to other options

Integrated technology for layered sand control and layered water injection

In order to solve the problem of water injection string failure caused by pipe creep and sand production in layered water injection wells, an integrated technology of layered sand control and layered water injection has been developed. A suspended large-radiuslayered mechanical sand control pipe column has been designed, providing sufficient design and usage space for the layered water injection pipe column. Developing a new type of anti-creep sealed packer can effectively improve the anti-creep performance of the water injection string and extend the validity period of the string. This technology integrates and optimizes layered water injection and sand control technology, large channel backwashing technology, integrated testing and allocation technology, and anti-creep technology of the pipe string. While effectively solving sand production in offshore water injection wells, it extends the service life of the water injection pipe string and reduces operating costs. Since 2018, this technology has been implemented in over 200 wells in Chengdao Oilfield, with a maximum of 6 layers for prevention and injection, a maximum well inclination of 48.8°, and a construction success rate of over 90%. It has achieved very good development results and economic benefits.

Study of the blocking mechanism in gravel packing based on CFD-DEM

Gravel packing sand control (GPSC), as the optimization of mechanical sand control technology, is widely used in the deep water completion and sand control of loose sandstone heavy oil reservoirs and highly argillaceous. To explore the blocking mechanism of GPSC, the influence of its structural parameters on the blocking of GPSC is investigated. This paper establishes a particle element model based on computational fluid dynamics-discrete element method coupling using the discrete element method and establishes a fluid flow model combined with computational fluid dynamics to realize their full coupling solution. And sand control experiments were carried out using a micro visual sand control simulation device to verify the blocking model. The blocking mechanism is analyzed from the microscopic point of view, and then, the influence of sand control structure parameters on the blocking in GPSC design is evaluated. The results show the following: (1) the blocking process of GPSC can be divided into three stages: an initial stage, sand accumulation stage, and equilibrium stage. (2) There are two main types of gravel packing blockage. The first type of blocking is blocking on the surface of the gravel layer. Sand particles on the surface of gravel layer mainly exist in the form of large particle size blocking gravel pores and sand particles bridging each other. The second type of blockage is the blockage inside the gravel layer. Sand particles mainly exist in the form of internal mud cakes and adsorption on gravels inside the gravel layer. (3) To ensure the sand control performance of the gravel layer, the gravel layer thickness is designed between 23 and 28 mm. The displacement or pressure of the on-site packing pump should be increased to ensure that the gravel layer packing solidity ranges between 59% and 62%. In the design of GPSC, it should be ensured that the median particle size of gravel is 5–6 times the median particle size of sand. This study provides an effective technical reference for the design of gravel structural parameters in on-site gravel packing completion sand control.

Study on Secondary Brine Drainage and Sand Control Technology of Salt Cavern Gas Storage

Geological conditions of salt cavern gas storage in China are characterized by dominantly layered salt layers with a high content of insoluble mudstone. After the water leaching of the salt layer, a large amount of sediment accumulates at the bottom of the gas storage cavity. During the gas injection process, only the clean brine above the sediment can be expelled, leaving a brine layer of 2–5 m and a large amount of brine in the pore space of the sediment. To increase storage capacity, it is urgent to explore the secondary gas injection and brine drainage technology to further expel residual brine in pores of the sediment at the cavern bottom. The sediment is relatively loosely packed and is composed of mudstone particles, which easily migrate and block the brine withdrawal pipe. In this paper, firstly, the mineral composition, particle size and distribution characteristics of the sediment at the bottom of the salt cavern are fully understood by XRD and sieve analysis methods. Then, a lab simulation device suitable for secondary gas injection and brine drainage of a high-salinity salt cavern with a diameter and height of 25 cm was designed and built. A screen sand control experiment, a gravel pack artificial wall sand control experiment and chemical cementing sand were simulated. The effects of gas injection, brine drainage pressure, brine layer height and insoluble particle size on sand production and liquid drainage were studied. The influence factors of brine withdrawal on the sand control in secondary brine drainage were intensively investigated, and finally, the gravel pack artificial wall sand control technology system was recommended. The optimal construction parameters for secondary brine discharge are recommended as follows: Under the condition of gravel packing with the same particle size, the trend of sand content with different artificial wall thicknesses is not obvious, and a 2 cm wall thickness is the best in the overall experiment, corresponding to 28 cm in the field. The larger the particle size of the gravel pack, the better the sand control, and the best gravel size is 10–20 mesh. The injection pressure should be as low as possible.

Robust and Fit-for-Purpose Sand Control Technology to Produce Marginal Reserves in EKP

East Kalimantan Petroleum (EKP) is an oil and gas exploration and production company which operates in East Kalimantan, Indonesia. Development of mature fields was aiming shallow unconsolidated sand-stone reservoirs which have high sand risk character. The proportion of shallow wells development compared to the main zone wells is tend to increase recently which has natural consequences of the increasing trend of sand-produced volume along with the hydrocarbon production. The sand grains abrasive physical property may cause consequences of a detrimental to the short-long-term productivity of oil and/or gas well. It can damage the hydrocarbon-contained surface facilities, and even causes a serious to catastrophic safety accident. The loss of containment leads might be followed by deadly disaster, such as fire and environment pollutions. The company currently produces these reservoirs type by applying the robust diesel-based chemical sand-consolidation (DB-SCON) technology for high stakes reservoirs and combined with the mechanical sand-screens application for the low stakes reservoirs. Along the field’s production period, the trend of a shallow unconsolidated reservoir’s average reserves is decreasing which lead to the declining trend of sand-control project economics. The company forms a project team under well intervention department to perform the research with the mission to find the new robust and fit-for-purpose sand-control technology application to produce the marginal reserves. The root causes analysis using current reality tree (CRT) reveals the three main factors of this economics declines trend: high chemical sand-consolidation investment cost, low-productivity and low-reliability of current mechanical sand-screen. The Analytical hierarchy process (AHP) defines the most robust and fit-for-purpose sand-control technology among the proposed alternatives: water-based chemical sand-consolidation (WB-SCON), high erosion resistance sand-screen (HERSS) and sand management (SM) technologies. As the result, the HERSS technology is chosen as the best solution among the alternatives. The field trials result compares HERSS performance to current robust DB-SCON. HERSS significantly reduces the investment cost by 68.0%, maintaining the reliability or success at 88.2% (DB-SCON recorded as 88.5%), maintaining the productivity at 2.5 MMscfd (gas production), accelerates the production two weeks earlier, and reduce the economic cut-off reserve limit from 0.1 down to 0.02 BCF. HERSS (made by zircon metal) technology is capable to significantly improve the performance of the mechanical sand-screen (Ceramic screen as current base-case). It increases the reliability from 64.7% to 88.5%, decrease the investment cost by 30.7%. The HERSS industrialization is planned in 2023 to replace current sand-control technology that potentially will generate significant economic improvement from the investment cost reduction with a total of $27.4 million.

The Gravel Packing Length Determination Method and Influencing Factors Analysis in Deepwater Horizontal Wells

Horizontal well gravel packing is the most commonly used sand control technology in offshore oil and gas fields. For extreme conditions such as deepwater, low fracture pressure formations, and long horizontal well bore length, targeted and cost-effective measures are required. According to the friction models in different stages of gravel packing process of horizontal well, the corresponding friction is calculated and compared. According to the calculation, during the entire packing process, the washpipe/screen annular friction is the largest in β wave packing stage, which reflects that higher packing pressure is required in this stage, and the formation fracture pressure is easily broken at this stage. According to the equilibrium flow velocity, the calculation method and flow chart of α -wave sand bed height were put forward. The criterion and calculation method of packing length were designed. The influencing factors of viscosity, density and leakage rate of carrier fluid on α-wave packing length were discussed. The quantitative analysis was carried out. The design and calculation method of α-β wave packing length considering the successful completion of α wave packing and the successful completion of β wave reverse packing was put forward. The corresponding software was compiled to discuss and calculate the quantitative analysis of the factors affecting the α-β wave packing length, such as the density of carrier fluid, gravel density and washpipe/screen ratio. For specific conditions, certain criteria and methods can be used to design and optimize horizontal well gravel packing length.

Study on sand control technology of balanced dense filling for the wells after multiple cyclic steam stimulation

Study on sand control technology of balanced dense filling for the wells after multiple cyclic steam stimulation

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.

Study on sand control technology of balanced dense filling for the wells after multiple cyclic steam stimulation

Study on sand control technology of balanced dense filling for the wells after multiple cyclic steam stimulation

Hydrocyclone technology for breaking consolidation and sand removal of the Natural gas hydrate

Natural gas hydrate is a promising substitute energy resource for the future. Currently, the inefficient sand control technology impedes the commercialization of Natural gas hydrate. The main challenge lies in breaking the consolidation of Natural gas hydrate and sands, and then separating micrometer-sized sands from the drilling fluid. In this paper, we present a technology based on hydroscyclone that effectively breaks the consolidations and removes sand. We used polypropylene powders and silica sands as substitutes for the hydrates and sands, and we added cement to replicate the consolidation. Inside the hydrocyclone, the material particles receive a strong shear force from the 3-dimension rotating swirling flow field generated by the device, as well as a centrifugal force produced by their own rotation and revolution. With the high-speed camera, we observed the effect of these forces breaking the consolidation and separating sands. It was further noted that the proportion of residual polypropylene powders in the recovered materials were between 0.46% and 1.05% after the materials were processed by the hydrocyclone. The low residual content of polypropylene powders demonstrated the success of hydrocyclone technology in breaking the consolidation and effectively addressing the problem of sand control in the extraction of Natural gas hydrate and sands.

Study and application of separate layer sand control and separate layer oil production technology in offshore unconsolidated sandstone reservoir

The unconsolidated sandstone reservoirs in Shengli offshore are characterized by many oil layers, long well sections, large interlayer, strong inter-layer heterogeneity and easy to produce sand. At present, offshore unconsolidated sandstone reservoir wells are using electric pumps and combined production, hence the inter-layer contradictions are prominent, which can not play fully role of each producing layer, restricting the development of offshore oil fields. Therefore, it is necessary to study separate layer sand control and oil production technology of electric pump well for 7 in casing production in Shengli offshore. Aiming at the problems of uncompaction and small diameter of general sand control method, a large diameter separated-layer sand control pipe is developed, which realizes separated-layer sand control and the following separate oil production. The oil and water swelling packer is designed to realize the stratified production. Through the design of on-line electric regulating valve, the flow of each layer can be adjusted. The technology has been tested in three Wells: CA2*-*, GO2-17-* and GO4-19-*. All the tests are successfully implemented, the water cut has been reduced to a certain extent, and the average daily oil is increased. It has achieved good results and will be applied more widely in offshore oil fields in the next step.

Perfection and Practice of Sand Control Technology System in Overseas River Oilfield

Perfection and Practice of Sand Control Technology System in Overseas River Oilfield

Optimization of Filling Sand Control Technology in Qu9 Guan3 Block of Qudi Oilfield

Optimization of Filling Sand Control Technology in Qu9 Guan3 Block of Qudi Oilfield

Experimental Study on Sand Inrush Hazard of Water-Sand Two-Phase Flow in Broken Rock Mass

In the western region of China, coal mining activities are prone to induce water and sand inrush disasters, which seriously threaten the safe production of the coal resources. In this paper, an experimental device was designed to simulate the process of water and sand inrush, and then, the control factors of the disasters in the broken rock mass in the goaf were investigated. Also, the seepage fracture channels in the broken rock mass were simplified by using the 3D printing technology, and the effects of fracture aperture and angle on the seepage characteristics of water-sand mixtures were analyzed. The experimental results showed that the porosity and skeleton structure of the broken rock mass were the key factors to control the water and sand inrush disasters. The smaller the initial porosity of the broken rock mass, the weaker its permeability, and the less probable to form a dominant channel for the water and sand inrush disasters. Conversely, the broken rock mass structure with larger size gradation was more likely to form the permeable channels, and the quality of the sand inrush was greater. In addition, it was also found that the angle of the fractures within the broken rock mass affected the seepage characteristics of water-sand mixture, and the permeability showed an exponential relationship with the fracture angle. Meanwhile, as the fracture aperture increased, the fracture angle generated greater influence on the permeability. Finally, we proposed the water and sand inrush prevention and control technology based on the experiment results. The results of this study can provide a reference for the control of water and sand inrush disasters in western China.

Research and application of solid-liquid dual material sand control technology

A new type of solid-liquid dual material artificial shaft wall sand control technology was developed for some special Wells (such as sidewall drilling, causing damage repair well, etc.) with low construction pressure and unsuitable mechanical sand control technology in dagang oilfield. The process is use solid and liquid mixing resin solution pump into the formation to form a complete artificial borehole wall, solid material filling the cavity of formation, act as proppant. Liquid as resin bonding agent, used for cementing solid material and formation of particles sand. In addition to evaluate the solid liquid double material of various performance indicators. Field test shows that this technology can be consolidated at well temperature, and the compressive strength can reach 8Mp and permeability can reach 1 μ m2 after consolidation. This technology has been successfully applied to sand control in 5 Wells in dagang oilfield and achieved good sand control effect.

Sand-Control Technology for Water Injectors Improves Well Performance

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 192840, “Field-Trial Results for New Sand-Control Technology for Water Injectors,” by Steven Fipke, SPE, Tendeka; J.E. Charles, SPE, Shell; and Annabel Green, Tendeka, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed. In 2014, a research and development (R&D) project was initiated to increase the life expectancy of Gulf of Mexico (GOM) Miocene and Lower Tertiary water-injection (WI) wells, several of which had suffered a severe loss of injectivity within only a few years of completion. The solution was to find a way to prevent fine material from entering the completion while sustaining high injection rates, with no loss of injection pressure or requirement for additional horsepower. A new flow-control device (FCD) and completion system were developed along with intrinsic nonreturn valves (NRVs) that prevent any backflow or crossflow during•shut-ins. Developing the Flow-Control Technology Tubing-deployed injection valves and regulators have been available for many years. However, these cannot address the problem of annular flow. The most-damaging factor in solids production is likely crossflow, wherein differently pressured injection zones can flow between layers inside the tubing or casing annulus. Crossflow can be eliminated only by blocking the flow at the sandface. This solution also would mitigate the damaging effects of water hammer by blocking pressure waves from entering the lower completion. Check-valve components must fit within sand-control screens or be deployed across multiple zones of the injection tubing.• During the R&D phase of the project, researchers used extensive laboratory testing, flow-loop testing, and computational-fluid-dynamics modeling to develop a series of NRV prototypes. The technology was designed to handle a variety of well conditions, including erosion, plugging, temperature, and repeated checking cycles. All FCD components, including the NRV technology, are manufactured with high-alloy stainless steel and tungsten-carbide components to resist tortuous downhole conditions for up to 15 years. FCD prototypes and design iterations were tested over 18 months and a final design was qualified to withstand repetitive pressure- checking cycles reliably at 1,500 psi (and up to 10,000-psi static differential•pressure).• The laboratory testing conducted to finalize the project development stage is described in detail in the complete paper; it consisted of leak-rate, erosion, plugging, and screen-construction stages. One determination of this testing was that the placement of the screen over the FCD joint could cause erosive wear because of the placement of the screen ribs over the valves. An alternative rib wire was designed that could place the FCD between wires without compromising the strength of the screen. With laboratory and workshop testing completed by early 2017, the focus of the project shifted to identifying and organizing a field trial for the new technology in a low-cost, low-risk environment.