Chapter 6 - Sand Control Completion Strategy

International field trials have demonstrated that sand production and control are crucial issues that need to be addressed and resolved to achieve the commercial exploitation of natural gas hydrate (NGH). The objective of this study is to investigate sand migration and control in sediments with different particle size distributions during depressurization-induced hydrate exploitation. A 50PPI (pores per linear inch) polyurethane foam was chosen as the sand control material to further explore its performance under conditions closer to actual field reservoirs, which is the continuation and extension of previous investigations. Experimental results confirm that the 50 PPI polyurethane foam demonstrates good sand control effectiveness for reservoirs with a median particle size (D50) of quartz sands ranging from 10 to 100 μm, even under material extrusion deformation. Under comparable reservoir conditions, finer and more heterogeneous sediments increase sand control requirements. Meanwhile, no definitive correlation between internal sand migration and actual sand production was observed. In reservoirs with fine quartz sand, sand production manifests as consolidated sediment migration after hydrate exploitation, while heterogeneous quartz sand reservoirs undergo significant internal changes before and after the NGH exploitation, accompanied by a evident decrease in gas production rate. Based on the experimental study, a theoretical framework for sand migration and production mechanisms during NGH exploitation is proposed, defining three distinct states. The state of sand migration shifts when local blockages reach a threshold, transitioning from particle migration to block displacement.

Sand production presents numerous technical, economic, and environmental challenges to the oil and gas industry. Sand particles may erode production equipment, resulting in increased maintenance costs and potential equipment breakdown. In addition, the influx of sand into the wellbore can lead to reduced production rates, reduced efficiency of reservoir sweep, and ultimately, reduced recovery of hydrocarbons. Also, sand production impacts project profitability because of the cost of sand control measures and potential lost production. There are two broad classes of methods used to control sand in oil reservoirs: mechanical methods are designed to physically restrict sand particles from entering the wellbore, while chemical methods involve the modification of reservoir properties to increase sand consolidation or fluid mobility. Chemical consolidation uses chemicals (resin, polymer gels, foams, nanoparticles, bacteria, etc.) to bind sand particles together to create a stable formation. For optimal sand control, combined approaches use a combination of mechanical and chemical methods. Sand management is an important part of oil and gas production, and several new technologies such as artificial intelligence and machine learning, autonomous sand monitoring systems, sand control measures, chemical sand control technologies, multilateral sand screens, advanced sand screen materials have been developed to improve sand management in the industry. Current developments and strategies in chemical consolidation techniques, sand management, control and prevention techniques are reviewed in this paper. Keywords: sand production; chemical consolidation; resin; polymer gels; foams; machine learning; artificial intelligence; sand monitoring systems.

Objectives/Scope This paper examines the sand production management strategies practised by Carigali-PTTEPI Operating Company (CPOC) to minimize the impact of excessive sand production on the processing facilities and well integrity as sand production from producing wells continues to increase. Sudden well interruptions could jeopardise the daily production delivery hence require all risks to be mitigated at early stage includes risk from sand production. Methods, Procedures, Process Gas reservoirs in CPOC operated fields were developed with monobore completions without active sand control. CPOC adopts the passive sand management approach, where sand is allowed to be produced to surface and later managed on the top-side facilities. The objective is to manage the produced sand using existing facilities and minimize the process upset/downtime. CPOC Sand Production Management consists of two main parts, Monitoring and Remediation. Two types of monitoring are done: Sand Production Monitoring and Corrosion/Erosion Monitoring. Ultrasonic Sand Detector has been used as the main tool for Sand Production Monitoring. Ultrasonic Testing (UT) has been carried out for all production flowlines as part of Corrosion/Erosion monitoring. Effective monitoring has become the enabler for proactive remediation actions. The remediation focuses on two areas: minimize sand production from wells (via MSFR/MASR-Maximum Sand Free Rate/Maximum Allowable Sand Rate), carry out water shut off, sand failure analysis etc.) and improve the integrity and reliability of processing facilities through upgrading activities. Result, Observations, Conclusions The interpretation of sand production from Ultrasonic Sand Detector allows qualitative and quantitative assessments of sand production and operational instruction for flowing wells via MSFR/MASR. In addition, UT survey is used to estimate the flowline remaining life. Proactive remediation of topside equipment is done in a timely and effective manner using Ultrasonic Sand Detector's data together with other inspection data. CPOC has also upgraded several topside equipment to improve the efficiency of sand removal, equipment integrity and reliability. This topside upgrade includes main processing platform sand removal upgrade, slug catcher cleaning, flowline wrapping, etc. This multidisciplinary collaboration since 2014, which integrate the monitoring of sand production from the wellbore with remediation activities of the downstream processes, has allowed CPOC to safely operate and achieve production target without loss of containment. Novel/Additive Information The sand production management strategies practised by CPOC not only allows the company to safely operate and achieve production target, it also enables the use of "slimhole monobore" completion which is economical and practical well design without the need for conventional downhole sand control, and results in well cost of <10 MMUS. This type of field development and sand production management has become a standard technology in the Gulf of Thailand.

Hydrocarbon production from unconsolidated sand reservoirs requires sand control usually consisting of the installation of a screen combined with gravelpacking. Several existing criteria such as Tiffin, Saucier and Coberly can be used for optimal selection of the sand control design. Sand and fines production in oil and gas wells are one of the main challenges and can result in failures of production systems. Especially in unconsolidated sand reservoirs, proper sand control practices are required to prevent reservoir sand production. At Staatsolie sizing of sand control design is based on the Saucier method incorporating the results of reservoir sand particle size distribution of side wall core samples.A Staatsolie-Suriname in-depth research of sand control practices in shallow, low-pressure, heavy-oil unconsolidated sand reservoirs completed with progressive cavity pumps will be presented. The conventional sand control method applied is the installation of formation sand sized wire wrapped screens and gravelpack completion on uniform and non-uniform distributed reservoir sands. Stand alone screen completions have revealed its application in uniform distributed reservoir sands. Sand production and control on depleted and complex reservoirs based on the conventional method has become a major challenge. In Suriname, in three onshore fields approximately 1,500 wells are completed and are in production. With improved sand control practices, failures have been reduced to less than 5 wells per year.The study has demonstrated the challenges and benefits of sand control in these complex unconsolidated Tertiary reservoirs. This has resulted into increased production and economic benefits. Results of lab tests and field cases will be presented and recommendations will be given on the best approach for sand control practices and the most cost effective sand control solutions in unconsolidated shallow sand reservoirs.

Formation damage, sand production and a HP/HT sour gas environment are major challenges in the field development of the Sawan gas reservoir in Pakistan. Meeting individual well productivity targets (average of 80 MMscfd) requires minimal-restriction (large bore or monobore) completions, minimizing formation damage via under-balance perforation and maintaining sand production below tolerable limits. The reservoir sands are extremely heterogeneous with many thin, weak layers. Sand control completion concepts are based either on internal gravel packs (IGP) or, if the weaker layers are less extensive, on selective perforation. To avoid having to kill the wells (which can lead to significant formation damage) the completions are run prior to perforating. This meant that the sand control decision for each development well had to be made in 3 to 4 days - between logging the well at TD and running the completion. The key elements of this "real time" sand management strategy were: the application of Fuzzy Logic computing techniques to correlate wireline log responses with core measurements, which enabled a field-calibrated, continuous sand failure prediction tool throughout the reservoir intervals;coupled well performance and geomechanical models to evaluate if selective perforation could safeguard well deliverability yet ensure sand-free production, standardization of critical completion equipment and simplified nipple-less completion design which provided the necessary operational flexibility, lowered overall completion cost, and reduced the risk of equipment failure.under-balanced through-tubing perforation with coiled tubing to minimize formation damage. This integrated completion and sand management strategy has delivered well production rates in excess of 100 MMscfd with sand production significantly below tolerable limits. It has also has created substantial cost savings and reduced completion failure risks compared to conventional cased-hole sand exclusion completions.

Experimental investigation of factors affecting gravel pack efficiency for thermal recovery wells in Bohai Bay, China

Sand production has been highlighted as one of the critical challenges for Zawtika Project. Throughout the years of field experiences, sand production management has brought up many challenges, especially in terms of field potential sustaining, well productivity and investment justification. Alternative sand control technique is one of the keys to overcome these challenges with continuous improvements driven by lessons learnt. Chemical Sand Consolidation (CSC) is the chemical sand control technique using the resin to bond the formation grain and strengthen the formation strength whereas Thru-Tubing Gravel Pack (TTGP) is retrofit sand control method, which the sand control principle is similar to conventional Cased-Hole Gravel Pack (CHGP), but can be installed in a smaller completion size. In Zawtika existing development phases, almost 150 zones of sand producing intervals are handled by CHGP completion design. In addition to CHGP, these mentioned alternative sand control techniques have been successfully implemented in 3.5-inch-tubing monobore completion for selected deep reservoir intervals after some degree of depletion. Field trial of CSC and TTGP had been implemented during 2019-2020 with 5 reservoirs in 7 monobore completion wells (4 CSC wells and 3 TTGP wells). All wells showed positive results with no sand production from the post-job production; and with a reasonable increase in Maximum Allowable Sand Free Rate (MASR). Based on well performance monitoring until early of 2022, all 3 TTGP wells as well as 3 CSC wells no longer have any sand production issue. Nevertheless, only 1 CSC well with water production history record prior to CSC implementation shows poorer performance on sand production prevention. Following the positive results of TTGP from the previous campaign in term of sand production prevention and well life extension, 8 more TTGP well candidates have been implemented in early of 2022. At the early phase of production, sand free production has been observed for all wells with 51 mmscfd incremental MASR. With all aspects of technical and fiscal evaluation proven to be successful, sand retention and production performance of CSC and TTGP are continuously monitored to confirm long-term performance efficiency for full application in the future. Zawtika sand management strategy through alternative sand control completion has been improved upon accumulated lesson learns and production experiences. The lesson learns and experiences from both operation and well performance monitoring will be integrated for further improvement for the next implementation phases. Maximizing gas potential through alternative sand control methods is also believed to be the cost-effective approach which strengthens PTTEP's competitive performance.

Research on sand control effect and micro-plugging mechanism of sand control medium in the development of natural gas hydrate reservoir

Since 1984, Peninsular Malaysia's gas fields have followed a distinct operational philosophy. In the initial field development, sand production was not considered a concern, resulting in wells and facilities without designs for sand management. Consequently, wells are confined to their maximum sand-free rate. Conversely, with reservoir pressure depletion, wells are beaned up to enhance drawdown, inadvertently introducing sand into the wellbore. This necessitates a delicate balance between sustaining production and managing sand effectively. This paper delves into how a highly sand-sensitive asset in Peninsular Malaysia's gas field navigates this challenge through the adoption of risk-based approach to sand management. The adoption of PETRONAS Carigali management guideline, aims to transition assets to a risk-based strategy, avoiding well shut-ins upon surface sand detection. Sand severity matrix was mapped as the initial analysis to assess sand erosion and transportation risks. Addressing sand issues starts with downhole management in wells lacking primary control. Remedial measures such as through tubing erosion-resistant sand screens, are installed. Following installations, monitoring enhancements involve acoustic sand sensors and online sampling, facilitate swift responses to sand surges, especially in satellite platforms. Acknowledging that sand controls may not entirely filter sand downhole; fines are managed through a closed loop online sampling. To identify flowline defects from sand erosion, radiographic and ultrasonic testing, especially at hotspots, is employed. Notably, routine pigging ensures a comprehensive approach to sand management within the platform. Field A led the way as the initial field in Peninsular Malaysia to pilot the adoption. With downhole sand control in wells producing sand, along with acoustic sensors and an online sand sampler, Field A saw 30% production increment, matching peak production in 2019. Despite success, one well continued producing fines below 45 microns. Sand erosion analysis tool indicated minimal erosional rate within limits, further confirming with ultrasonic and radiographic testing, UT/RT done previously, allowing the well to flow with risk assessment. This served as a pivotal milestone, where wells were previously restricted even with insignificant sand presence. Post-sand screen installations, pigging operations showed minimal sand accumulation in pipelines. Planned UT/RT inspections at each flowline will provide further insights. In mature fields, the occurrence of sand production becomes inevitable. By incorporating downhole sand control, real-time sensors, online sand sampling, continuous flowline integrity monitoring, and regular pigging, operators can proactively manage sand production in the long run. This strategy enables the optimization of production while mitigating the risk of equipment damage or operational disruptions stemming from sand-related challenges. A field that, for the past decade, maintained zero tolerance for sand is now transitioning to an acceptable level of sand production. Addressing sand management solely downhole is insufficient; comprehensive measures on the surface are required, fostering accountability across all parties to facilitate the transformation of a sand-sensitive asset.

After several downhole sand control failures in subsea wells,1 the Okwori field development underwent a significant change of direction both topside and sub-surface. Numerous constraints were taken into account and successfully managed: tight rig schedule, complex logistics, contractual issues, etc…. Downhole, the original multi-zone, fully selective sand control completion system hat included sand screen expanded inside casing was abandoned. A new system was designed that allowed similar selectivity but with open-hole sand control. The new completion system implied a change in drilling practices, reservoir drill-in fluid and cake cleanup techniques that required simultaneous engineering. These in-depth modifications were designed and implemented in a matter of months. Topside, the FPSO had not been equipped to deal with sand production since downhole sand exclusion was assumed to be reliable enough. A sand management study recommended a series of modifications that minimized production shut-down while safely handling the produced sand and oil. Test de-sanding using a temporary sand trap determined that sand produced from weak formations could be stabilized. Severe service chokes were installed allowing production at a constant liquid rate. Experience accumulated to date highlights the importance of appropriate planning and application of reliable technical solutions in subsea completions. Introduction Due to the high associated costs, subsea well development concepts are usually "interventionless". The initial costs of these wells are mainly due to the mobilization and day rates of sophisticated drilling rigs. To re-enter subsea wells, similar rigs are required, hence the prohibitive cost of well intervention1. This is the driver behind declaring these wells "interventionless". Once the "interventionless" nature of these wells has been stated, it is presented as a challenge to well engineering. To provide a reliable solution, the most robust techniques for construction and completion are required. As subsea wells are expensive, each completion must give access to sufficient reserves for economical justification. in sacked and compartmentalized structures, sufficient reserve per completion means complex wellpaths penetrating multiple targets as beads threaded into a necklace. When co-mingling is not an option and sand exclusion is required, these wells also become host of expensive jewelry. We know since 1948 2 that more equipment is run in a hole, the more can and will go wrong. Hence the interventionless concept becomes the "Quest for the Holy Grail" of engineering. This pursuit translates into a risk based search for the best engineering practices and proven technologies that are compatible with the project economics, combined with best practice implementation. Risks that could adversely affect the project must be mitigated and required measures must be implemented so that the project remains economical throughout its life. In the Okwori project offshore Nigeria, the Addax Petroleum and service provider personnel tackled all of these issues in record time. A Complex Subsurface Okwori subsurface is far from the traditional image of a big oil anticline into which wells are positioned to maximize recovery. Okwori field is a chaotic ensemble of superimposed hydrocarbon and water bearing pools that are separated by faults3. Today, more than 250 fault-dip closures have been identified, 59 of them with proved hydrocarbon content. For additional information, please refer to references 3 and 4. Figures 1 and 2 illustrate the highly compartmentalized nature of the field both laterally and in depth. To access these scattered reserves the development plan called for dispersed well-head locations, hence a subsea development with each well being individually tied back to a central floating production separation and offloading vessel (FPSO).

Sand production has historically been a problem associated with some consolidated, poorly consolidated, and unconsolidated sand formations. The result is usually lost production due to formation sand and fines plugging gravel packs, screens, perforations, tubular, and surface flow lines or separators. Completion methods applied to minimize sand production include: gravel packing, sand consolidation, critical production rate, oriented/selective perforation, FracPacking, or any combination of these methods. These techniques are used in consolidated, poorly consolidated, and unconsolidated sand formations. However, there are no guidelines available in the literature on how these methods are selected. Mechanisms for sand failure include: tensile, shear, cohesive, and pore collapse. Additionally, failure due to chemical effects can occur when the cementation materials are weakened due to chemical interactions. Many mathematical models have been presented in the literature to predict sand failure, and consequently determine sand production. These models are based on different failure mechanisms and include: pressure drawdown/compressive strength, failure based on a given failure criterion such as Mohr Coulomb, cohesive strength failure, elastoplastic failure around a perforation, viscoplastic modeling, and empirical correlations. However, there are no guidelines on how these models are applied based on the characteristics of the sand formation. Experimental studies have been presented in the literature to model sand failure. These studies include sand arching, hollow cylinder strength, triaxial and hydrostatic, and large scale testing. Laboratory testing are designed to study a given failure mechanism, and thus to predict sand production. The objective of this paper is to categorize sand formations that potentially exhibit sand failure and sand production. Based on this characterization, an appropriate laboratory testing and mathematical modeling are recommended, and a completion method is suggested. Examples from standstone reservoirs in Saudi Arabia will be used to demonstrate certain methods used for sand control.

Summary The depressurization method for natural gas hydrate exploitation encounters the difficulties of low productivity and sand production. Enhancing hydrate production efficiency and reducing massive sand production are the key issues to be solved in hydrate development. This paper proposes a new approach to hydrate reservoir stimulation and sand control by liquid-solid phase change proppant (LSP) filled in radial well (SCRP). A multicomponent flow model of sand-water-gas-hydrate is established and applied to evaluate the effect of SCRP on hydrate development. The results obtained show that the application of SCRP realizes an integrative effect of both reservoir stimulation and sand control. Radial wells increase the sweep area of pressure drop and promote hydrate decomposition. Solid particles, which are formed by LSP, not only fill and support radial wells but also act as sand control medium, preventing sand from flowing into the production well. It is found that reducing the production pressure difference can effectively reduce sand production. To achieve a large-scale stimulated reservoir volume, it is necessary to increase the length of a single radial well, the number of radial wells in the same layer, and the number of radial well layers. The spiral layout of radial wells has a better effect on improving gas production. A single radial well achieves good sand control effect with the application of the LSP system, but an increase in radial well number leads to an increase in sand production, resulting in massive amounts of sand gathered in the production well. As a result, in the case of multiple radial wells, other sand control technologies, such as mechanical sand screening, should be used along with SCRP to further reduce sand production.

In many sandstone reservoirs, the production of sand presents a major obstacle to well productivity. The petroleum industry spends millions of dollars each year to prevent and repair sand control problems including reduced production rates, sand bridging, erosion of equipment and sand disposal and removal. Conventional Sand Screen Systems currently available on the market and manufactured mostly by service providers and are predominantly metallic in construction; these conventional screens have limitations on sustaining high downhole velocities resulting commonly in downole erosional failure and premature loss of downhole sand control. Erosional failure can commonly be associated in applications where high gas rate are anticipated. Commonly, these applications also combine with these higher gas rates, higher downhole temperature, pressure and sour well enviroments which magnify the corrosion-erosional issue with time. Lower erosion resistance leads to premature failure of sand screen resulting in sand production and frequent workovers/intervention. A higher cost and deferred production ensues for the well owner. Worse still, wells with failed sand control can become marginal or uneconomical to produce at these lower rates. Sand production can at times result in operational failure of well control equipment resulting in a higher HS&E risk. Well intervention especially offshore/subsea provokes a higher risk and cost associated and should be avoided through competent technical specification of technology equipment suitable for these applicational environment. If a material change from metal can be made to offer the resistance to erosional and corrosional failure, risk from loss of sand control and reduced economic return on well investment can be mitigated. Ceramic Sand Screen Systems which offer a material change where brought to the market in 2010 and offer a unique sand control solution which are ideal for such well conditions. Ceramics are more than 50 times harder than steel and are universal corrosion resistant to various acids and bases even at higher temperature. This paper introduces the material change from metallic to ceramic technology, testings, and some successful field case studies.

Sand and fines production is one of the oldest problems in the petroleum industry and one of the toughest to solve. Today, many technologies and methods exist; in some cases some sand and fines production is manageable, while for others it cannot be tolerated at all. Also, many wells do not produce sand or fines from the onset and may not require an active sand control solution until later in their lives. Sand influx into the wellbore may lead to various down-hole and surface problems. Chemical sand control solutions have been around for many years and have always been attractive due to their ability to be installed without any restrictions to the well bore geometry. However due to the difficulties with placement, and in many cases their association with formation damage, there have been reservations regarding the use of chemical methods as a standard sand control method. This paper presents a unique and novel chemistry that increases the maximum sand/fines free rate without a significant reduction in permeability and discusses the placement techniques essential for a successful application. It includes a review of laboratory tests, treatment design considerations and study of some wells that have been treated with zeta potential altering chemistry. Introduction Approximately 70% of the world's oil and gas reserves are found in poorly/weakly consolidated reservoirs. Sand production has been a major concern to the industry for decades, and has become more critical today as higher drawdowns and deeper depletion schedules are implemented. Sand influx may lead to various problems such as erosion of valves and pipelines, plugging of production casing/liner, sand deposits in the separators and direct economic loss due to production limitations. Besides overburden and reservoir depletion another major mechanism that directly causes or enhances sand production is water breakthrough. Water breakthrough may cause the loss of natural cementation of the rock and alteration of the capillary pressure. Mechanical methods are considered highly reliable and depending on the applications and economic drivers for the field or well; there are various options in the industry that range from highly sophisticated (Frac Packs, Expandable screens, etc.) to simpler systems (slotted liners, standalone screens, etc.). When sand production is predicted to become an issue during the life of the well, operators have to choose to install a mechanical sand-control system during the completion, perform an intervention during the life of the well or rely on reducing the sand production by choking back the well. A major concern when a well is completed without any form of sand control or if the mechanical method has failed is that passive methods, such as reducing the drawdown will inhibit the commercial viability of the well or even the field. Hence the use of chemical methods becomes more attractive. The introduction of an advanced chemical method that alters the zeta potential of sandstone formations, present a new remedial sand and fines control solution with little to zero reduction in the permeability.

Sand production is a well-known issue in oil and gas fields. It can lead to other sand-related issues such as well plugging, erosion, production downtime, etc. The issues can be more serious, not only to the loss of wells and production facilities but also to safety and the environment. Therefore, sand management is a critical aspect of oil and gas production, ensuring operational efficiency, equipment integrity, and environmental protection. This paper presents an integrated solution project for proactive sand management, encompassing both subsurface and surface control strategies. The paper describes strategies for integrating control techniques, empathizing with their role in mitigating sand-related issues. The sand-related issues from the fields were observed and mapped. The active sand control methods were selected: mechanical and chemical agglomeration. The concept of a chemical solution is to provide a larger agglomerate of grains sands and stronger bond strength between particles, resulting in longer agglomerated sand particle longevity. The chemical agglomeration was comprehensively tested in the laboratory with actual downhole and surface sand samples, and it is agglomerating them into much larger particles that promote the performance and integrity of the sand screen and production separator/desander at downhole and surface facilities, respectively. In the downhole control, the sand screen was installed, and injection was done simply with a bullheading method. This technology has proved to improve production in the field with rapid payback period. Meanwhile, surface control can be applied to separator/desander facilities and shows immediate agglomeration with the chemical and enlarged sand grain agglomerates and settled at the bottom. Both strategies can increase oil and gas production and improve operational efficiency and equipment integrity. The findings and recommendations from this paper contribute to enhancing sand management practices in the oil and gas industry, promoting cost-effectiveness, asset reliability, and environmental stewardship.