Sand Screen Research Articles

Spatially resolved CFD-DEM model with innovative experimental validation methods to improve understanding of sand retention in oil and gas wells with the consideration of filter-beds on standalone screens

Coupling CFD and DEM is commonly used to study particle-fluid flow in sand retention systems for oil and gas wells, addressing the limitations of laboratory experiments and reliance on empirical data. These numerical studies aid in optimising standalone sand screens, which are favoured over gravel-pack completions for cost-effectiveness. However, such studies overlook the critical role of the bulk filter-bed in retaining permeability for both particulate and fluid phases. This paper presents a robust numerical methodology using resolved CFD-DEM to model a sand retention system that accurately captures filter-bed permeability, which has a greater impact on sand production and retained fluid productivity than the screen itself from a long-term perspective. The numerical model's accuracy is validated through a novel experimental methodology, which involves benchmarking the numerically derived porosity and single-phase permeability against micro-CT imaging of the filter-bed. Results show strong consistency between the numerical model and micro-CT imaging of the laboratory-derived filter-bed. This validated model provides a solid foundation for running more accurate sand retention tests and improving standalone sand screen selection criteria. Future work will explore the effects of varying parameters on the filter-bed formation to determine optimal conditions for maximising sand retention while maintaining hydrocarbon productivity from a long-term perspective.

CFD-DEM study on the blocking conformation of pre-filled sand control screen by layering method

Preventing screen blockage due to sand poses a significant challenge. The article combines computational fluid dynamics (CFD) and discrete element method (DEM) to establish a fully coupled four-way interaction model. A sophisticated size particle injection model was established, taking into account the particle size distribution (PSD) characteristics of the formation. A layering method was used to study the sand control behavior of a high-performance pre-filled screen. The study also quantitatively investigated the impact of factors such as median sand size (D50), screen structure, and fluid velocity on both wellbore-screen annulus and internal screen plugging patterns. The findings reveal that the sand retention rate within the wellbore-screen annulus exceeds 93.8 %. The risk of pre-filled screen blockage is minimized when the ratio of gravel diameter to sand diameter falls within the range of 3.3–5. At a gravel filling rate of 97 %, fine sand predominantly moves radially, resulting in a low risk of blockage at the screen's entrance layer, thereby favoring oil and gas production. In cases with elevated fine sand content, it is advisable to maintain a production flow rate below 3 m/s to mitigate localized erosion damage caused by increased pressure resulting from screen blockage. This model holds significant importance in optimizing completion tools and production parameters.

Technology Focus: Sand Management (October 2024)

With the resurgence of drilling activities post-COVID-19, there is a growing interest in refining existing technologies and exploring new ones to discover cost-effective and reliable solutions for developing aged and more-challenging new reservoirs. Although approaches may vary slightly depending on the unique characteristics of reservoirs in different regions, the general trends are conceptually similar. Drilling longer wells, increasing the number of fracture stages, and completing multiple zones in complex stacked reservoirs, along with optimizing multilateral wells with sand control to enable long laterals in stacked reservoirs, have emerged as key focuses of the industry. Drilling longer wells introduces several challenges, including managing installation loads, ensuring proper wellbore cleanout, and ultimately producing effectively and uniformly from extended laterals that drill through heterogeneous reservoirs with varying sand facies. While liner flotation is effective in reducing installation loads and improving wellbore cleaning, it presents challenges when used in conjunction with conventional sand-control screens. Sand control and flow control are becoming more integrated to offer solutions for effective production from longer laterals. Flow segmentation helps prevent premature failures caused by gas or water breakthroughs or localized high rates causing erosion. Paper SPE 218074 is a good example of using flow-control devices to enhance the reliability and longevity of sand-control systems. Stacked reservoirs have always posed challenges in terms of zonal isolation and sand-control design. Higher fines content and silty sand with complex reservoir conditions leads to less interest in standalone screens because of the high risk of plugging and failure in such developments. Even though gravel packing is effective, it poses several technical and implementation challenges. The complexity of sandface completion, with varying sand sizes, pressures, and fluid properties, makes these wells particularly difficult to complete. Paper SPE 214914 offers a good case study of such a complex completion successfully implemented in the field. Despite all this, the fundamentals of screen design and implementation remain the same. Screen plugging remains one of the major challenges in the sand-control industry. Rigorous testing of sand-control media to verify retention properties, erosional resistance, integrity requirements for the installation-loading and lifelong-loading scenarios, and plugging resistance are critical aspects of any sand-control qualification. I strongly recommend reading paper IPTC 23690 for a detailed understanding of the screen-qualification process and the design of screens for target sand facies. Also, it is crucial to remember that no screen is completely immune to plugging. The unintended consequences of a change in drilling/completion fluid or cleanout process could lead to screen plugging. It is always important to test and validate the effect of any change in fluids or completion practices on sand-control performance. Recommended additional reading at OnePetro: www.onepetro.org. SPE 215070 A Comprehensive Review of Screen Plugging During Openhole Sand-Control Completions Installation: Causes, Consequences, and Best Practices by Maye Beldongar, SLB, et al. SPE 214934 Shunted Gravel-Pack Failures and How To Prevent Them by Carolina Latini, DuneFront, et al. SPE 215411 Performance of Bonded Bead Sand Screen as Remedial Sand Control in Highly Erosive Environment by Ashvin Avalani Chandrakant, Petronas, et al.

Deep Eutectic Solvent as a New Zeta Potential Altering Chemical for Sand Agglomeration.

Fines migration can cause various issues, such as plugging of the sand screen and damage to tubings. There are two chemical sand control methods: consolidation and agglomeration. Consolidation works by injection of a solvent into the formation to harden over time and hold the sand in place, while agglomeration works by altering chemical properties of the sand surface to attract and clump up sand. Various chemicals have been used for research in sand control. Some chemicals for consolidation, mostly resins, have been effective in consolidating sand but may cause permeability impairment, which will reduce production. Some chemicals for agglomeration such as a polymer with amines have been less effective or are nonbiodegradable. In this work, a novel deep eutectic solvent (DES) and ionic polymer combination as a fines stabilizer is formulated in-house and tested through extensive experimental study. The development of chemicals is based on agglomeration principles which determine the range of zeta potential reduction that can be achieved to destabilize, coagulate, and flocculate the fine particles together with different combinations of DESs and ionic polymers tested systematically using the design of experiment (DoE) method. The chemicals are then tested for compatibility with reservoir fluids in the jar test. The optimized formulation is characterized by thermogravimetric analysis (TGA) for limit of temperature degradation and laser particle size analysis (LPSA) for the extent of particle size. The novelty of this work is the development of a greener and more cost-saving in-house DES and ionic polymer combination as a fines stabilizer chemical, which is effective for both injection or production wells after stimulation or enhanced oil recovery (EOR) treatments. Due to the tunable nature of the DES, the formulated chemical can be tailored for various reservoir conditions to cater to specific requirements.

A comprehensive review of cased hole sand control optimization techniques: Theoretical and practical perspectives

Cased hole sand control is a critical aspect of oil and gas well management, ensuring efficient production by mitigating sand production issues. This review presents a comprehensive review of cased hole sand control optimization techniques, offering theoretical insights and practical perspectives to enhance well productivity and longevity. The review encompasses various aspects, including the challenges of sand production, the importance of sand control, and the evolution of sand control techniques. Sand production in oil and gas wells can lead to equipment damage, wellbore instability, and reduced production efficiency. Effective sand control is thus essential to maintain well integrity and maximize hydrocarbon recovery. This review explores the fundamental principles of sand control, highlighting the key parameters influencing sand production, such as reservoir properties, fluid properties, and wellbore geometry. The review discusses traditional sand control methods, such as gravel packing and standalone screens, along with emerging technologies like expandable sand screens and autonomous inflow control devices. It evaluates the advantages and limitations of each technique, considering factors such as installation complexity, cost-effectiveness, and long-term reliability. Furthermore, the review delves into advanced sand control optimization strategies, including the use of modeling and simulation tools to predict sand production and optimize sand control design. It discusses the integration of data analytics and machine learning techniques for real-time monitoring and decision-making, enhancing sand control effectiveness and reducing operational risks. Practical case studies and field applications are presented to illustrate the implementation of sand control optimization techniques in real-world scenarios. These case studies highlight the challenges faced, the solutions implemented, and the outcomes achieved, providing valuable insights for industry practitioners and researchers. In conclusion, this review provides a comprehensive overview of cased hole sand control optimization techniques, emphasizing the importance of integrating theoretical knowledge with practical considerations to enhance sand control efficiency and maximize well productivity. his review paper will systematically analyze existing methodologies and the latest advancements in cased hole sand control treatments. It explores theoretical frameworks, compares practical outcomes, and discusses the implications of optimized frac geometries for reservoir performance enhancement across varied geological settings.

Intelligent Completion Enables Zonal Isolation Offshore Malaysia

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22882, “Advancement of Openhole Gravel Pack and Zonal Isolation With Selective Intelligent Completion in Deepwater Malaysia,” by Elvy Samuel, SPE, Noppanan Nopsiri, and Lee Chan Fong, PTTEP, et al. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. _ As fields mature, drilling and completion design and execution for infill development become more challenging. In a deepwater environment, one strategy is to target several reservoir packages in a single wellbore. This technique frequently presents technical challenges, however, because penetrating different zones requires active reservoir management, an allowance for zonal isolation, and an adequate response to potential crossflow. The complete paper presents a completion strategy implemented in an intelligent well completed in the Malaysian deepwater Block K. Introduction The SNP Field is 125 km offshore Sabah in approximately 1350–1400 m water depth. The field crosses the boundary between Block K and Block G, approximately 15 km from the Kikeh floating production, storage, and offloading (FPSO) facility. The field commenced Phase 1 in 2011 with the completion of nine oil producers as openhole gravel packs (OHGPs) and five water injectors with expandable sand screens at the sandface. Phase 2 development, partially covered in the complete paper, commenced in the third quarter of 2021 with three standard oil producers and one smart producer well. All SNP Phase 2 wells were completed as OHGPs targeting various sand reservoirs in a common pressure regime. The well discussed in the complete paper addressed subsurface uncertainties related to depth and the pressure differential between the upper zone (UZ) and the lower zone (LZ) and the isolation requirements of the middle zone (MZ) by implementing an intelligent completion architecture with an OHGP with zonal isolation on the sandface. The flow diversion between the producer zones would be achieved through the deployment of an intermediate completion coupled with an intelligent completion architecture in the upper completion. The well was placed on production in the first quarter of 2022 to the Kikeh FPSO, achieving the targeted rates solids-free. Gravel-Pack Design In this field, the fracture pressure window is marginal, suggesting that a conventional OHGP approach would be challenging. Adding to this complexity is the zonal-isolation requirement. To achieve the objective of complete openhole (OH) coverage and to enable zonal isolation simultaneously, shunt-tube technology was identified as critical. The selection of shunt-tube technology allows the following achievements: - Premature screenout mitigation, because the technique is a proven system that enables the slurry to bypass any restriction in the OH/screen annulus - Zonal-isolation capabilities by combining shunted sand screens and OH mechanical packers with selective shunt-tube isolation capabilities - Application of diverter valves, crucial in fields with marginal fracture pressure windows

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

Wear Analysis of NiTi Sand Screens Using Altair Discrete Element Method.

This research explores discrete element method analysis to investigate the wear of NiTi Sand Screens in comparison to traditional materials. The study utilized Altair EDEM v2022.2 software and employed Oka and Archard models to simulate the wear behavior of Nitinol, a well-established Shape Memory Alloy (SMA). The mechanical properties considered include Poisson's ratio, solid density, shear modulus, and Young modulus. Results indicate significantly higher wear values and deformations with the Oka model compared to negligible wear with the Archard model. The Oka model's emphasis on impact as the primary wear mechanism, supported by high normal cumulative energy, better represents sand screen wear phenomena. Additionally, this study indicates that factors such as particle size distribution and normal and tangential cumulative contact energy hold potential as predictors of wear response and characteristics. The Oka model demonstrated that NiTi exhibited reduced wear losses compared to SUS630 and Cr-Mn white cast iron, both of which are recognized for their high toughness when subjected to an impact load. Experimental analysis validated the simulation findings with morphological and graphical erosion plots. The limitation of observing the shape memory effect through DEM (discrete element method) simulation was acknowledged. Recommendations include characterizing post-wear microstructural changes, exploring the influence of temperature on wear behavior, and further research to refine wear models and understand SMA sand screen responses.

The Impact of Autonomous Inflow Control Valve on Improved Oil Recovery in a Thin-Oil-Rim Reservoir

Summary Oil production from thin-oil-rim fields can be challenging as such fields are prone to gas coning. Excessive gas production from these fields results in poor production and recovery. Hence, these resources require advanced recovery methods to improve the oil recovery. One of the recovery methods that is widely used today is advanced inflow control technology such as autonomous inflow control valve (AICV). AICV restricts the inflow of gas in the zones where breakthrough occurs and may consequently improve the recovery from thin-oil-rim fields. This paper presents a performance analysis of AICVs, passive inflow control devices (ICDs), and sand screens based on the results from experiments and simulations. Single- and multiphase-flow experiments are performed with light oil, gas, and water at typical Troll field reservoir conditions (RCs). The obtained data from the experiments are the differential pressure across the device vs. the volume flow rate for the different phases. The results from the experiments confirm the significantly better ability of the AICV to restrict the production of gas, especially at higher gas volume fractions (GVFs). Near-well oil production from a thin-oil-rim field considering sand screens, AICV, and ICD completion is modeled. In this study, the simulation model is developed using the CMG simulator/STARS module. Completion of the well with AICVs reduces the cumulative gas production by 22.5% and 26.7% compared with ICDs and sand screens, respectively. The results also show that AICVs increase the cumulative oil production by 48.7% compared with using ICDs and sand screens. The simulation results confirm that the well completed with AICVs produces at a beneficial gas/oil ratio (GOR) for a longer time compared with the cases with ICDs and sand screens. The novelty of this work is the multiphase experiments of a new AICV and the implementation of the data in the simulator. A workflow for the simulation of AICV/ICD is proposed. The simulated results, which are based on the proposed workflow, agree with the experimental AICV performance results. As it is demonstrated in this work, deploying AICV in the most challenging light oil reservoirs with high GOR can be beneficial with respect to increased production and recovery.

Reservoir Drilling and Openhole Gravel Packing with High-Density Cesium Formate Fluids in a High-Pressure, Marginal Mud Window Environment at Martin Linge

Summary High-density cesium/potassium (Cs/K) formate fluids were successfully utilized from reservoir drilling to upper completion installation in five productive Martin Linge high-rate gas wells. Four wells were completed with openhole gravel pack (OHGP) and one with standalone sand screens. The gravel packing operation marks what is considered to be the highest density carrier fluid OHGP successfully completed worldwide, with a specific gravity (SG) of 2.06. A complex operation under pressure and temperature conditions (745–780 bar and 135–140°C) that almost qualify as high pressure/high temperature (HP/HT), including managed pressure drilling (MPD), overbalanced screen running, and openhole gravel packing, was simplified by using the same base brine throughout the operation. Cs/K formate reservoir drilling fluid (RDF) and screen-running fluid were designed with biopolymeric additives and minimal calcium carbonate bridging particles. Clear Cs/K formate brine was chosen as gravel pack (GP) carrier fluid. The use of Cs/K formate fluids for all stages of the operation reduced the complexity of transitioning between the operational stages. In addition, the reservoir was only exposed to one filtrate without application of damaging weighting solids. The drilling fluid contributed to successful MPD and delivered wells with very good hole quality in the reservoir, which consisted of interbedded sandstone, coal stringers, and shale. The shale-stabilizing properties of concentrated formate brine–based fluids provided acceptable conditions for extended openhole time and allowed additional logging runs, including pore pressure measurements, under near-HP/HT conditions, before running the screens. One bottom-up cleanout was conducted before the screen-running fluid was circulated in and the screens installed. The spurt and seepage losses were low throughout the drilling and screen-running phases. No breaker treatment was required in any of the wells. All wells have proved to have good initial productivity and high well productivity index. The successful OHGP operations performed with the high fluid densities required in Equinor’s Martin Linge field have set a new standard for well completions in challenging high-pressure environments.

Subsea Multilateral Oil Producer Evaluated With Acoustic and Production-Logging Tools

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210299, “A Subsea Multilateral Oil Producer, Completed With AICD Sand Screens and Selective Inflow Valves, Is Evaluated by Combined Acoustic and Production-Logging Tools, Identifying the Sand-Producing Branch and a Tubing Leak in a Single Operation,” by Duncan Troup, SPE, Archer; Tim Griffin, SPE, Three60Energy; and Minh Pham, Aker BP, et al. The paper has not been peer reviewed. _ A horizontally completed subsea multilateral well exhibited unexpected sand production and a tubing leak, leading to the well being shut in. The complete paper discusses the novel tools and techniques used to localize the tubing leak, identify the bore responsible for sand production, and provide relative sand quantification at differing flow rates. Well Background and History The well was drilled and completed as a subsea producer to be tied back to an existing floating production, storage, and offloading (FPSO) vessel by means of a subsea flowline. After drilling of the first lateral, the decision was taken not to complete it. A second lateral was then drilled and completed. The main and secondary bores were drilled into different zones of the reservoir. Both lower completions used standalone sand screens, autonomous inflow-control-device nozzles, and swell packers set in open hole. Each of the lower completions was fitted with a hydraulically actuated inflow control valve (ICV) for managing production flow from the reservoir zones, providing the ability to produce each leg independently or commingle them. The upper completion is equipped with two gas lift valves (GLV) to provide artificial lift, a chemical injection mandrel, and a surface-controlled subsea safety valve (SCSSV). After approximately 6 months of flowing the well, water cut was seen to increase and a series of “popping” events occurred in which productivity increased markedly for short periods. Significant quantities of sand soon began to accumulate in the FPSO topside facilities. Approximately 1.5 years after startup, well productivity decreased sharply over a few months while the water cut continued to increase. As the productivity continued to decline, the leak rates exhibited by the SCSSV and one GLV fell outside the acceptable criteria. The pressure responses indicated a high leak rate. The well was shut in pending diagnostic logging and repair of the leak. Sand-Source Investigation The subsea wellhead of this well was fitted with an acoustic sand detector, but this had only indicated minor amounts of solids in the flowstream over the producing lifetime of the well. An extensive investigation concluded that the makeup of the collected sand was most likely to have originated in the case study well and that the amounts involved were likely to have been a contributing factor in the loss of well integrity. Because the well was producing from two different branches, a probability existed that only one of these was suffering from sand production. The well completion was designed to allow independent control of the branches by use of ICVs, so an intervention to assess the status of each of the branches with respect to water and sand production was planned, with the additional objective of diagnosing the well-integrity failure.

Technology Focus: Sand Management (October 2023)

As drilling and completion activity resumes post-pandemic, the sand-control market faces several logistical challenges. Inflation and supply-chain interruption concerns are expected to continue into 2024 because of high volatility in raw material pricing amplified by geopolitical tensions in Europe and the South China Sea. As oil price strengthens, consumer preferences shift and more operators investigate newer technology and focus more on performance than price. Despite these factors, the fundamentals of sand control and sand management remain the same. As more-challenging reservoirs are being developed and new difficulties arise, however, more engineers are questioning the conventional sand-control aperture-sizing wisdom. Any sand-control effort aims to manage solids production while creating the fewest restrictions to fluid flow. To assure that sand-control efforts meet these goals throughout the life cycle of the wells, engineers must design them in a way that can withstand the forces of nature, doesn’t erode with high and localized flow, doesn’t corrode with the harshness of produced fluid, and doesn’t mechanically deform during installation and life-cycle loads. If you are interested in diving into these design processes, paper IPTC 21158 provides insight. With the higher adaptation of flow-control devices in recent years to improve flow segmentation and reduce the premature failure of sand control because of highly localized flow, flow-control-device implementation is becoming an integral part of sand-management strategy. More papers every year discuss the design process and field implementation of various kinds of flow-control devices along with sand controls. Paper SPE 210299 provides good insight into some of the field challenges and results of implementing flow-control devices with sand control. As always, monitoring for sand and solid production is key in any sand-management effort to assure the integrity of the system and maintain the containment of the fluids. In the past year, several papers focused on monitoring, including discussions of new technologies and presentations of field case studies. Paper IPTC 22989 is among the interesting papers in this subject. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 21223 Lesson Learned From First Application of Openhole Standalone Screen With Autonomous Inflow Control Devices in Oil Field Offshore East Malaysia by Catherine Ye Tang, Petronas, et al. SPE 210128 Erosion-Resistant Sand Screen: Development and Deployment by Antonio Lazo, Chevron, et al. SPE 208162 Prediction of Threshold Sand Rates From Acoustic Monitors Using Artificial Intelligence by Ronald E. Vieira, University of Tulsa, et al.

Design and feasibility analysis of a new completion monitoring technical scheme for natural gas hydrate production tests

As a prerequisite and a guarantee for safe and efficient natural gas hydrates (NGHs) exploitation, it is imperative to effectively determine the mechanical properties of NGHs reservoirs and clarify the law of the change in the mechanical properties with the dissociation of NGHs during NGHs production tests by depressurization. Based on the development of Japan’s two offshore NGHs production tests in vertical wells, this study innovatively proposed a new subsea communication technology—accurate directional connection using a wet-mate connector. This helps to overcome the technical barrier to the communication between the upper and lower completion of offshore wells. Using this new communication technology, this study explored and designed a mechanical monitoring scheme for lower completion (sand screens). This scheme can be used to monitor the tensile stress and radial compressive stress of sand screens caused by NGHs reservoirs in real time, thus promoting the technical development for the rapid assessment and real-time feedback of the in-situ mechanical response of NGHs reservoirs during offshore NGHs production tests by depressurization.

Integrity Assessment of High-Performance PVC Pipes for Thermal Wells.

In wells with high-viscosity crude oil, steam injection is used to improve the fluidity of the heavy oil. Screens made of steel are employed for sand control, with corrosion being a serious problem. Non-metallic pipe materials, such as novel high-strength PVC, are therefore being tried out. This paper presents the results of an integrity assessment of large-diameter hard PVC pipes under compressive loading. Plain, built-up, and slotted pipes were subjected to a 3-month aging process in saline water. Strain gauge sets were used for dynamic testing of longitudinal and transverse deformations. Values of fracture strength, total deformation, and anisotropy (Poisson's ratio) were extracted from the stress-strain graphs and analyzed. Upon aging in saline water, the stiffness of all pipes increased and was the highest for slotted pipes. Maximum stress after soaking was reduced by 11-12%. The ductility was the highest for plain pipes and the lowest for built-up pipes. Poisson's ratio remained almost constant for all pipes and aging conditions. The good news for field applications is that overall, aging had only a minor impact on the major compressive properties. The main conclusion was that corrosion-prone steel pipes and sand screens can be successfully replaced by corrosion-free high-strength PVC pipes and screens for water transport applications in thermal wells. This work provides a scientific basis for the structural integrity assessment of this new PVC and helps field engineers in the proper pre-deployment selection of pipes for target oilfields.

CFD-based erosion modelling of sand screen using dense discrete phase model: Investigating carrier fluid type effect

Sand screens that are widely used in petroleum industry, can fail due to erosion. Since carrying fluid type can have a considerable effect on erosion, in this study, dense discrete phase model (DDPM) was utilized to model sand screen erosion using a CFD-based technique under air, water, and oil flows with four different sand types. The results showed that, erosion was much greater in liquid flows than in air flows. For liquids flows, erosion increases as the uniformity and the sorting coefficients of sand decrease. It has been concluded that, when sand contains various sizes under a certain fluid type, the significance and contribution of particles related parameters on erosion depend on sorting and uniformity of the produced sand.

Sand control screen erosion-failure prediction method in weakly consolidated sandstone reservoir

Sand production is one of the most common problems encountered in oil and gas field development, particularly in weakly consolidated sandstone reservoirs. Mechanical sand control screens are widely used to mitigate sand production. However, sand containing production fluid can lead to screen mesh erosion wear and sand screen prematurely failure. In this study, an experimental device was developed to simulate the local “hot spot” screen erosion damage considering the actual downhole radial sand carrying flow. The experimental results show that the erosion mass loss of the screen is positively correlated with the sand fluid velocity, sand concentration, median sand particle size and erosion time. A comprehensive sand screen erosion prediction model is established, which presents the correlations between erosion mass loss and various parameters, such as sand median particle size D50, sand concentration, fluid erosion velocity and erosion time. Compared with the field data, the predicted results accuracy of the effective life of the screen is more than 80%. The new sand screen erosion prediction model proposed in this paper can effectively predict the screen's erosion rate and service life in the field.

Evaluating the screen performance in sand control design by laboratory sand retention test

To produce oil and gas from unconsolidated sandstone reservoirs, sand screens are necessary to control sand flowing from the formation into the wells, causing well pluggings. In open hole completion, stand-alone sand screen is an essential component to prevent sand production, thus, selection of suitable sand screens is critical to minimize sand production and optimize the well’s production life. 
 Nowadays, premium screens with steel meshes make the openings of the screen slots complex in shape, resulting in a very different effect of sand retention compared to the traditional screens. The sand retention test is considered a standard and must be conducted to select screen opening and size, which decides the sand prevention capacity of the screen. 
 The paper presents the factors affecting the results of laboratory sand retention tests and proposes solution in the direction of considering the data trend rather than relying completely on the output results. The paper also brings about the evaluation method through the change the screen’s permeability to have better qualitative results compared to the traditional methods.

Rigless Wireline Logging Approach Locates, Addresses Water Sources

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208547, “Locating Source of Water Production and Performing Cost‑Effective Rigless Remedial Operations in Deviated Wells Completed With Standalone Sand Screens,” by Andrey Timonin, SPE, Schlumberger, and Eldar Mollaniyazov, Dragon Oil. The paper has not been peer reviewed. _ Field examples presented in the complete paper describe a fit-for-purpose logging approach for locating sources of water production accurately and executing rigless water-shutoff operations to increase cost-effective hydrocarbon production in cased wells completed with standalone sand screens. After remedial operations, the authors observed a significant decline in water production and an increase in oil rates in all remediated wells. Introduction The operator was granted a production license for exploration and development of oil and gas resources in the Cheleken Contract Area in the Caspian Sea. The area consists of two offshore oil and gas fields, Dzheitune (LAM) and Dzhygalybeg, in water depths between 8 and 42 m. The fields consist of two elongated anticlines at the eastern end of the prolific hydrocarbon Apsheron Ridge. The LAM field is a multilayer reservoir with pressure regimes producing at various gas/oil ratios with complex inflow profiles downhole. Most of the wells drilled in the LAM field were completed with 9.625-in. casing and 7-in. liner across the reservoir section. The A sand reservoir, at depths of 1500–1800 m, and the CH sand reservoir, below 2000 m, are produced separately by using dual-string tubing to avoid crossflow. Over time, depletion in reservoir pressure caused formation failure in the A sand reservoir. Wells producing from this formation began to produce sand. As a result, the operator had to change the completion strategy for newly drilled wells and recomplete some old wells by pulling dual-string completions out of hole and running in hole single tubing with sand screens across existing perforations. Some wells completed with standalone sand screens across the A sand reservoir experienced water breakthrough over time. Locating the source of water breakthrough and achieving timely intervention to shut off water inflow is paramount to keeping these wells producing at economically optimal oil rates. Overview of Rigless Wireline Logging and Intervention Techniques Rigless wireline logging and intervention techniques, the implementation and components of which are detailed in the complete paper, were used in several wells in the LAM field to shut off water production in a cost-effective way. The three field examples demonstrate rigless logging and intervention results in wells completed with standalone sand screens.

Permeability decline by fines migration near sand control screens in steam assisted gravity drainage: A numerical assessment

The near-wellbore permeability loss caused by the release and migration of naturally fine particles impairs the well productivity in oil reservoirs. The damage would be intensified in the presence of restrictions such as sand control screens due to retardation and accumulation of fine particles resulting from flow convergence and high volumetric flux.This study focuses on the experimental investigation and mathematical modeling of the permeability impairment near the sand control screens under a representative fines migration process for the SAGD well conditions. For this purpose, the single-phase flow experiments were conducted on unconsolidated sand packs in a sand retention testing (SRT) setup. The testing used different sand screens and considered the chemical effect of the fines migration process and different salinity for the saturating brine and flowing fluid. A 3D numerical model incorporating governing fluid and particle transport equations in porous media and an empirical permeability loss equation was established to simulate the fines migration process.The results show that the sand screens with a low open flow area and narrow aperture size cause higher permeability loss under the same flow conditions. Higher salinity reduction yields higher mobilized fines concentration, causing high near-screen permeability loss. For the salinities above 800 ppm, no significant pressure drops were observed. Furthermore, changing salinity to deionized water (DI) caused almost complete plugging of the sand pack, masking the flow performance of the sand control screen. A good match was obtained between the measured and calculated dimensionless pressure drops from the experimental and numerical models. The calibrated model could accurately enough predict the dimensionless pressure drops for the near-screen interval. It was confirmed that the porous medium's model parameters were nearly independent of the sand screen. However, different results were obtained for different salinities, confirming the 'parameters' dependency on not just porous medium but also fluid properties.

High-Temperature Water-Based Drilling Fluid Accesses Depleted Deepwater Reserves

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207825, “First Use of Novel High-Temperature Water-Based Reservoir Drilling Fluid To Access Depleted Deepwater Reserves,” by Alexandra C. Morrison, Conan King, SPE, and Kevin Rodrigue, Halliburton. The paper has not been peer reviewed. _ A combination of divalent base brine and high wellbore temperature presents significant challenges for high-density aqueous reservoir drilling fluids. Such systems traditionally use biopolymers as viscosifiers; however, they are subject to degradation at elevated temperatures. Nonaqueous drilling fluids are thermally stable, but complete removal of the filter cake is challenging, which can lead to formation damage. The complete paper describes the qualification and first deepwater drilling application of an aqueous reservoir drilling fluid at temperatures greater than 320°F. Introduction The laboratory development and scale-up yard trials of the high-temperature divalent brine-based reservoir drilling fluid (HT-RDF) and solids-free screen running fluid (SF-SRF) systems used for this well took several years. Specific rheology and fluid-loss targets were set and met during the design phase, and, in conjunction with hydraulic modeling, software simulations demonstrated that equivalent circulating densities (ECDs) would be acceptable based on well-construction plans. The HT-RDF showed excellent thermal stability in static age tests, which was crucial because of the plans for openhole logging of the production zone once total depth was reached. Screen plugging was identified early in the project as a key risk; the most-suitable mitigation for this was to engineer a completely solids-free fluid in which to install the sand screens. The resulting SF-SRF was designed to provide fluid-loss control and wellbore stability in case filter cake was stripped from the formation face during the screen run. Finally, given the focus on production maximization, the fluids underwent rigorous formation-damage tests, ultimately showing that a return permeability of greater than 60% was possible with the inclusion of an acid breaker to assist filter-cake dissolution.