Sand Control: Sand Characterization, Failure Mechanisms, and Completion Methods

The use of expandable screens simplifies completion proce-dures. Many operators perceive that screen performance de-pends on whether it is fully compliant with open hole; how-ever, it is impossible to guarantee total compliance. Evidence indicates that, in addition to filling the micro-annuli and plug-ging the screen, mobile fines and sand have the potential to create hot spots and erode the screen, thus creating sand-production problems. This paper presents laboratory results that illustrate the feasibility of applying a curable, low-viscosity composition to stabilize and strengthen unconsolidated formations. Over-displacement is not necessary in this process. The composition forms a tacky, ultra-thin film, creating bonds between grains that cure with time and temperature once coated onto the sur-faces of formation particulates. Unconsolidated formation sands, even those with high content of clay fines, were con-solidated with negligible loss of initial permeability. The results obtained from this study demonstrate the im-portance of stabilization of the formation. The screens, whether wire-wrapped, pre-packed, expandable, or simply slotted pipes, serve as a mechanical support to prevent col-lapse of the wellbore. A combination of treating unconsoli-dated formations with an ultra-thin, curable composition and installing a mechanical liner should provide an economical and reliable means for sand control. The use of such curable sand-stabilization treatments may therefore eliminate the per-ceived need for compliant expansion, placing a premium on the mechanical strength of the sand-control technique selected. Introduction Wellbore instability often results from a combination of me-chanical and chemical instability; however, mechanical factors play a dominant role in wellbore instability during the drilling phase of operations. Drilling a well in a formation changes the initial stress state and causes stress redistribution in the vicin-ity of the wellbore. The redistributed stress state may exceed the rock strength and cause failure.[1, 2] Once a wellbore or a perforation tunnel is introduced into a friable sand formation, a plastic zone develops and formation failure can follow. Production and cyclic loading are the main reasons a plastic failure zone expands into a formation. For-mations that are considered soft or poorly consolidated are often plagued by sand production. Formation sand production can result inplugged gravel packs,plugged sand screens,plugged tubulars, and potentially sand fill in the surface flow lines and surface equipment, as well aslost production.3–6 In addition to damage caused by plugging, sur-face equipment can be eroded because of abrasive, sand-laden fluid flowing from the well. In a worst-case scenario, sand-production problems can cause total well failure or the need for recompletion resulting from casing collapse, openhole col-lapse, or both. Conventional treatments for sand-producing wells include gravel packing, frac-packing, formation consolidation, and squeeze treatments using resin-coated sand slurries. These treatments control sand production and are based on gravel-packing technology that relies on the creation of stable bridges at the face of the formation to minimize damage to the pack. The filtering mechanism provided by the gravel pack is effec-tive for controlling sand production, but the permeability of the pack can decrease over time. This decreased permeability results from a continuous migration of formation fines toward the wellbore, which causes progressive plugging and results in high skin damage and reduced productivity. Sand-Control Screens The primary function of screens is to provide mechanical support to prevent proppant or gravel placed in the perforation tunnel and formation from flowing back into the wellbore. Keeping proppant in place will support the perforation tunnel and/or fracture thus maintaining a highly conductive flow path into the wellbore. In all gravel pack and frac-pack comple-tions, the gravel and proppant act as the primary filter to help prevent fines migration and sand production.

Sand production is major problem for the oil and gas industry and solutions to this problem is a continuous process as new challenges arise with time. Various sand control methods have been proposed for tackling the sand production challenge, and research and experience have shown that the use of mechanical sand control methods are more suitable, with gravel packing being the most effective. Gravel packs are proven to be an effective mechanical sand control technique, and a good gravel pack completion design is of great importance to exclude sand from the wellbore while enhancing well productivity. Implementation of sand control by gravel packing in the Niger Delta is usually found to require importation of commercial gravel for the purpose of sand control which is a challenge in terms of high purchasing and transportation costs with import taxes. A solution is presented in this study which involves sourcing for gravel locally and investigating its suitability for sand control by gravel packing. Locally sourced gravel was compared with commercial gravel using sieve analysis and results showed that the locally sourced gravel closely met the requirements of the commercial gravel depicted by slot widths that are close to that obtained by the commercial gravel. Based on the results of this study, favorable performance is expected when locally sourced gravel is used for sand control by gravel packing in unconsolidated formations in the Niger Delta. It is recommended to source for different gravel types from different locations and evaluate using sieve analysis and Laser Particle Size Distribution Analysis to determine suitable gravel types for these type of formations.

When the formation is unconsolidated, sand particles can be produced into the wellbore. Such production of sand particles is undesirable as it lowers the permeability of the producing zone, erodes surface and downhole equipment. Costly intervention may be required to mitigate the damage to the well integrity and the reservoir deliverability. The most common methods of controlling this unwanted sand production involve: 1. Filter produced fluids through a gravel pack retained by a screen or 2. Use of consolidating fluids such as resin, a curing agent, along with other chemicals to create a conducive environment for the resin curing reaction to occur. The gravel packing completion requires special tools and equipment therefore higher cost. In the case of sand control by chemical consolidation, the resinous material tends to have relatively uncontrollable setting times, strength, placement, and regained permeability leading to unsuccessful treatment. With both cost and treatment effectiveness in mind, it is desirable to develop an improved material and method to mitigate sand production by consolidating the formation sand without impairing well productivity or injectivity. The present paper describes the development of a unique chemistry for sand control in unconsolidated formations. This chemistry involves using positive charge modified nanoparticles that can self-assemble over the unconsolidated formation sand particles to form a layer of consolidating material thus preventing any unwanted sand production. The new consolidation treatment material consists of colloidal nanoparticles modified using a cationic modifier and ionic strength modifier that can be placed downhole as a single pill. The pill has high affinity to the solid surface therefore less prone to build up in the pore space. Once cured at reservoir temperature it forms a thin layer of hard gel around the surface of the sand particles, thus cementing the sand grains together at the same time maintaining open porosity to ensure easy flow of produced hydrocarbons or injected water. The newly developed sand consolidation formulation was studied for their ability to consolidate loose sand and at the same time maintain good permeability. The effect of various ionic modifiers on consolidation properties was studied. The ability of the cationic modified nanoparticles to self-assemble around unconsolidated sand and eventually cure to form a consolidated sand pack was investigated. Regain permeability studies showed good regain permeability of the consolidated sand pack. Furthermore, this paper describes the concentration effect of the cationic modifier on the regain permeability. Finally, it shows that the new product provides a controllable curing time, thus avoiding any premature setting of the nanoparticles in the wellbore.

Sanding in hydrocarbon producing and water injection wells has been a severe problem in unconsolidated formations. Many technical solutions have been evaluated by the industry. These solutions encompass mechanical sand exclusion methods such as screen, gravel packing, and frac and pack. Various production and completion practices such as controlling the production rate and following specific well completion guidelines to minimize sand production have failed to provide satisfactory returns. Several limitations such as screen plugging and high costs associated with deploying expandable screens make the current mechanical sand control practices more expensive. With both cost and treatment effectiveness in mind, chemical sand consolidation could present the most cost effective remediation and prevention opportunity. Additionally this would also allow the wellbore to be free of tools, screens and pack sands. In this paper we describe the development of a unique chemistry for mitigating sand production in unconsolidated formations. This chemistry involves using cationically-modified nanoparticles that can self-assemble over loose formation sand to form a layer of consolidating material thus preventing any unwanted sand production. The new consolidation treatment material consists of colloidal nanoparticles modified using a cationic modifier and oligomeric activator that is initially low viscosity fluid. The fluid has high affinity to the solid surface therefore less prone to build up in the pore space. Once cured at reservoir temperature it forms a thin layer of hard gel around the surface of the sand particles, thus cementing the sand grains together at the same time maintaining open porosity to ensure easy flow of hydrocarbons and injected water. The ability of the new fluid to consolidate loose sand and at the same time maintain good permeability was investigated. Various oligomeric activators were studied with particular focus on effect of concentration temperature and shear. The ability of the cationic modified nanoparticles to self-assemble around unconsolidated sand and eventually cure to form a consolidated sand pack was investigated. Regain permeability studies showed excellent regain permeability of the consolidated sand pack. It was also shown that the new sand control fluid system provides a controllable curing time, thus avoiding any premature setting of the nanoparticles in the wellbore. The novelty of the newly developed sand consolidation system is its ability to self-assemble around unconsolidated sand and eventually cure to form a consolidated sand pack while maintaining good permeability.

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.

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

Sand production is produced alongside oil and gas from the subsurface formation which is one of the unceasing problems faced generally in the oil and gas industry during the production phase. Sand production is usually initiated by sand when the formation stress exceeds the strength of the formation. It occurs when soft rock fragments break down as reservoir decreases, leading to lose grains that go along with hydrocarbons to the well and up to the surface and consequently leading to damage of subsurface and surface equipments. As it is known of it’s non-economical, environmental, and safety values to the oil and gas industry thus demanding remedy solutions and mitigation methods. This sand production as it is of no use entails a sand control measure or mitigating methods to reduce its production to lower extent in order to effectively optimize production, produce at a faster rate, and monitor sand control wells, and it is essential to evaluate the well’s performance, sand control effectiveness, and the durability of the equipments used in order to achieve the prime aim of oil and gas production. Several techniques have been made and approached toward the minimization of sand production from wells. The choice of the techniques chosen varies from simple fluctuations to difficult and costly completions. The sand control method usually chosen or selected depends on many factors such as the geology, type of environment, and consideration cost of the project to be executed. This article will focus on the most used and advanced sand control techniques which are gravel pack, expandable sand screens, and sand consolidation.

Various logging tools have been tested in the Groningen gas field to: .Determine thepresence, size andshape of cavities behind perforated production casings caused by formation sand production..Evaluate the success and quality of gravel packing operations. Cavities can be detected, but extensionfrom the borehole cannot be quantified. In gravel packs, gravel tops, pack density, failures, etc. can be evaluated qualitatively.

Sanding in oil production and water injection wells has been a severe problem in a sandstone formation. Many technical solutions have been evaluated by Saudi Aramco. These solutions encompass mechanical sand exclusion methods such as screen, gravel packing, and frac and pack. Various production and completion practices such as controlling the production rate and following specific well completion guidelines to minimize sand production have failed to provide satisfactory returns. Several limitations such as screen plugging and costs associated with deploying expandable screens make the current mechanical sand control practices more expensive. Chemical sand consolidation could present the most cost-effective remediation and prevention opportunity. Additionally, this would also allow the wellbore to be free of tools, screens and pack sands. With the cost benefit and technical challenges in mind, a new chemical system was developed to effectively consolidate loose sand, which has caused injectivity and productivity decline and costly clean out operations. The newly develop chemical system is based on resin backbone with a curing agent to harden under reservoir temperature. A permeability enhancing additive is incorporated in the system to achieve excellent and controllable regained permeability of the consolidated sand pack. This paper presents the new advancements in preventing wellbore sand production. The newly developed sand consolidation chemical was studied for their ability to consolidate loose sand and at the same time maintain good permeability. The new sand consolidation chemical system showed several key advantages over the current commercial products, including its easy mixing procedure and superior performance in consolidation strength and regained permeability. It was shown that the permeability enhancer incorporated in the new sand consolidation product is the key to maintain superior regained permeability. In addition, it was shown that the new product provides a controllable curing time up to several days, thereby avoiding any premature setting of the resin in the wellbore. Furthermore, the new system is also compatible with acids to eliminate any post-job production issues if the formation is acidized in the future.

Gravel packing can be successfully performed on high-angle wells (70°-80°) when special consideration is given to the completion design and details of field procedures and practices. Through analysis and modification of current techniques and research done on full scale models, Chevron experimented with and developed several techniques to successfully gravel pack high-angle wells . The high-angle gravel packs were performed utilizing the following criteria: solids free completion fluids, low-side perforating, modified screens, combination tools (circulating pack), maximum tailpipe (washpipe)-liner ratios, medium viscosity carrier fluids, maximum pumping rates, and special attention to quality control. Sand-out pressures, subsequent pack tests, quantity of gravel placed (percent packed volume) and extended flow tests of up to 20 MMCFD have proven the success of the design and procedures implemented.

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

Low-temperature oxidation (LTO) of crude oil has been employed to investigate its potential as a sand consolidation technique. Loose sand (20/30 mesh) saturated with crude oil (18 – 20 API) and brine was subjected to air injection at a low temperature (100 – 150 C) for a period of time (6 – 18 hours). The sand packs developed compressive strengths ranging between 375 and 1264 psi and suffered a maximum permeability loss of 22%. It was found that higher oxidation temperatures reduced the consolidation time and increased the compressive strength; but had no effect on the magnitude of permeability loss. Heavier oils required less oxidation time, caused slightly larger permeability losses, but had an insignificant effect on compressive strength. The presence of clay enhanced the LTO reactions by shortening the oxidation time and increasing the amount of residue deposited on the sand grains. This greatly increased the compressive strength, but at the expense of larger permeability losses. When interstitial water was present with clay, the permeability loss was increased further while the compressive strength was slightly reduced. Acid treatment had no effect on the residue deposited on the sand grains. Experimental testing as well as two predictive models showed that this technique provides sufficient compressive strength to withstand sand-free, high flow velocities and results in much smaller permeability losses compared with plastic consolidation. Introduction Sand production is considered to be one of the major operational problems in producing poorly consolidated reservoirs. Sand influx into the wellbore may lead to various problems such as erosion of valves and pipelines, plugging the production liner and sand accumulation in the separators. Cleaning and repair works related to sand production plus loss of revenue due to production rate restriction amount to great costs incurred by the industry every year. Furthermore, undetected erosion of production equipment may pose a major safety hazard in case of high-pressure gas wells. Therefore, sand control has attracted much research effort for more than six decades. Several methods are commonly used to prevent or reduce the flow of sand particles into the wellbore during the course of production. These methods use either mechanical means (sand screens, filters, perforated or slotted liners, gravel packing) or chemical agents (plastic consolidation). Certain completion and production practices are also employed to minimize or prevent sand production. Most existing sand control methods have their own drawbacks. In the mechanical methods, the setting of liners and gravel packing around liners may require a long time which adds to the cost. Moreover, the formation sand is still free to move and hence may plug the gravel pack or liner. In the chemical methods, some difficulties may arise in achieving polymerization of the injected resinous material in the formation - to consolidate sand particles - and still maintain adequate permeability. Furthermore, these resinous materials are proprietary and quite expensive. All these drawbacks leave a substantial and unfulfilled need for a sand control method capable of effectively preventing the flow of sand particles into the wellbore. Low-temperature oxidation of oil had been experimented with as a means of in-situ consolidation of sand. In this paper, the results of a new form of this process are presented. Low Temperature Oxidation Crude oils react with oxygen through numerous and complex reactions. These reactions have been found to fall into distinct categories depending on the reaction temperature. At temperatures below 500 F, the low temperature oxidation (LTO) reactions are dominant, and produce mainly oxyginated hydrocarbons such as alcohols, aldehydes, ketones, acids and hydro-peroxides with little carbon oxides. P. 547

Petro-Canada operates a number of thermal and non-thermal projects in the oil sands and heavy oil areas of Eastern Alberta and Western Saskatchewan. These projects have been plagued with low pump efficiencies, slow rod fall, fluid pound, solids production and overloaded pumpjacks. Petro-Canada's solutions to these problems on steam, fireflood and primary producers in unconsolidated sand formations are presented in this paper. Specific topics include completion practices, bottomhole pump designs, sand control equipment and production techniques. Introduction Production of heavy oil, whether on primary or with the assistance of enhanced oil recovery techniques, is far more difficult than recovery of conventional light oil. Production wells at Petro-Canada have gone through many stages of development. Earlier wells were designed to obtain both production and information. Cost effectiveness, reduced maintenance and improved production were the bases of later well designs. Standardized completions have evolved for primary (Fig. 1), steam (Fig. 2) and fireflood (Fig. 3). Casings All surface casing is 244 mm. 48.1 kg/m. H-40, ST+C. Heavy oil wells use large 178 mm production casing so that sand control devices can be installed if necessary, larger tubulars can be used to reduce rod fall problems, dual completions can be considered, and conversion a f a field from primary to EOR can be readily accomplished. Primary wells are completed with 178 mm, 29.5 kg/m, K-55 ST+ C casing. The preferred casing on thermal completions is 178 mm, 34.2 kg/m, MN-80, Buttress, landed in tension but not prestressed. Fireflood wells use non-exotic alloys for all of the wellbore except across the zone of interest, where nickel alloys are run. Cements Good cement bonds, with minimal loss of cement into formations are the main objectives of Petro-Canada's cementing programs. A typical primary cement would consist of Class "A" + 3% CaCl2 for the surface casing, 2: 1:4 Pozmix for the upper 70% of the production casing, and Class "G" + 3% KCl for the lower 30% of the production casing. Fireflood wells subsitute Ciment Fondue, extended with alumina silicate firebrick, for the lower 30% of the production casing. Steam wells are frequently located in areas where lost circulation of cement is a problem. The use of lightweight cements (1,400 kg/m3) reduces the loss of cement. Free pipe for the upper 20 to 30% of the well and wellhead growth of up to 0.6 m while steaming a well is not uncommon. A typical thermal cement for a steam well could consist of 50% Class G, 25% spheres and 25% Silica Flour. Foamed thermal cements have been used on a few wells. Wellheads Blowout preventors are bolted to 279 mm, 14 MPa slip-on casing bowls welded onto the surface casing. All production casings, whether primary or thermal, are landed in slips in the surface casing bowls. Primary wellheads are bolted directly to the surface casing bowl and consist of a 279 mm by 179 mm by 14 MPa tubing head with lock down screws, tubing hanger for 73 mm EUE tubing, 179 by 73 mm bonnet, 73 mm BOP, 73 mm Flow tee and 73 mm stuffing box.

Production of formation sand continues to be a major operating problem for Production of formation sand continues to be a major operating problem for the petroleum industry, particularly in the geologically young and poorly consolidated reservoirs of the Gulf Coast area. Remedial through-tubing gravel-pack installations have been greatly simplified through the use of specially designed setting tools and a highly viscous, cross-linked polymer, gravel-carrying fluid. Based on field data, this technique or design application has been highly successful. The term gravel or gravel packing herein is intended to mean any matter used as a packing material. packing material Introduction Recovery of oil and gas from poorly consolidated sand formations continues to be a major challenge to the petroleum industry. Sands is usually entrained in fluids produced from such formations, causing equipment erosion and surface handling problems. Often sufficient volumes of sand will enter the production string to completely block or severely restrict fluid flow, making production impossible or prohibitively expensive. In reservoirs where sand production is a problem, economic production of oil and gas cannot be achieved without some mechanical method of sand control (gravel pack, prepack or chemical consolidation). When a formation is known to produce sand, some measure of sand control should be included in the initial completion. However, in many cases, formation characteristics are not known and wells are completed without sand control. Sometimes these wells produce for months or even years before sand production becomes a problem. Consequently, hundreds of wells in the Gulf production becomes a problem. Consequently, hundreds of wells in the Gulf Coast area are currently sanded up and off production. Many will remain off because of the prohibitively high cost of a major rig workover to pull the production tubing and install sand control. This is not a new problem, and for years the industry has attempted to perfect through-tubing sand-control techniques as an economic means of returning these wells to production. Some limited degree of success was obtained with both production. Some limited degree of success was obtained with both through-tubing chemical consolidation and gravel-packing methods. Because of the high failure rate on completion and the limited life associated with chemical consolidation processes, a harder look was again taken at through-tubing gravel packing.