Evaluation of Latest Technological Advances in Sand Control Completions: A Case Study

2021 ◽  
Author(s):  
Rishabh Bharadwaj ◽  
Manish Kumar ◽  
Shashwat Harsh ◽  
Deepak Mishra
Keyword(s):  
Oil And Gas ◽  
Control Method ◽  
Control Mechanisms ◽  
Sand Production ◽  
Production Rates ◽  
Reservoir Properties ◽  
Water Contact ◽  
Technological Advances ◽  
Sand Control ◽  
Gravel Pack

Abstract Sand control poses huge financial loses during production operations particularly in mature fields. It hinders economic oil production rates as well as damages downhole and surface equipment due to its abrasive action. Excessive sand production rates can plug the wellhead, flow lines, and separators which can result in detrimental well control situations. This paper will provide a comparative study on various sand control mechanisms by reviewing the latest advancements in sand management techniques. This study evaluates the performance of through-tubing sand screens, internal gravel pack, cased hole expandable sand screen, modular gravel pack system, openhole standalone screen, multi-zone single trip gravel pack, slim gravel pack, and chemical sand consolidation mechanisms. Various field examples from Niger-Delta, Mahakam oil and gas block, and offshore Malaysia are examined to gain an insight about the application of aforementioned sand control methods for different type of reservoirs. This study enables the operator to tackle the sand production problem according to the well construction changes during the life cycle of a well. The internal gravel pack completion system delivers a prolonged plateau production regime in shallow depths. In high drawdown conditions, chemical sand consolidation completion incurs early water breakthrough and elevated sand production. Chemical sand consolidation technique yields better results in deeper formations and its placement can be improvised by implementing coiled tubing and diversion techniques for multi-stage treatments. Depending on the well inclination, gas-water contact, producing zone type and thickness, well age, and economy, the completion types out of modular gravel pack, openhole standalone screen, slim gravel pack, and through tubing sand screen is recommended accordingly. Acquiring offset data, well log analysis, particle size distribution and performing pressure tests will improve the data quality of the obtained reservoir properties. This will further help in the selection of the most suitable sand control method for the target reservoir.

Imperatives for Implementing Gas-Lifting for Fields with Sand Control: OT Field Experience

2021 ◽  
Author(s):  
Kingsley Iheajemu ◽  
Erasmus Nnanna ◽  
Somtochukwu Odumodu
Keyword(s):  
Control Mechanism ◽  
The Other ◽  
Control Mechanisms ◽  
Sand Production ◽  
Stable Production ◽  
Sand Control ◽  
Open Hole ◽  
Gravel Pack ◽  
Production Problems ◽  
Gas Lift

Abstract Unconsolidated sandstone formations are normally completed with one form of sand control or the other. The aim is to manage sand production as low as reasonably practicable and protect well and surface equipment from possible loss of containment. There are about 8 broad types of sand control namely; internal gravel pack, external gravel pack, chemical sand consolidation (SCON), open-hole expandable sand screen, cased-hole expandable sand screen, stand-alone screen, pre-packed screen and frac & pack. Gas-lifting targets to increase pressure drawdown required for wells to produce by injecting gas at a pre-determined depth using gas-lift valves installed in the tubing. Whereas gas-lift design targets to optimize the gas-lift injection to ensure stable production, the associated drawdown may challenge the operating envelope of the sand control mechanism in place. The OT field has been in production for about 50 years and has been on gas-lift for about 20 years. There have also been occasional sand production problems in the field; some of which occur in gas-lifted wells. This paper will highlight the outcome of a study that investigated the performance of various sand control mechanisms under gas-lift production and present observed trends to serve as guide in maximizing the performance of such gas-lifted wells with sand control mechanism.

Extending Gravel Pack Carrier Fluid Performance in Highly Deviated Well for 7-Inch Gravel Pack Completion without Shunt Tube by Using High Grade Suspension Gravel Pack Fluid in Mahakam Offshore

2021 ◽  
Author(s):  
Putu Yudis ◽  
Doffie Cahyanto Santoso ◽  
Edo Tanujaya ◽  
Kristoforus Widyas Tokoh ◽  
Rahmat Sinaga ◽  
...  
Keyword(s):  
Control Method ◽  
Oil And Gas Industry ◽  
High Rate ◽  
Control Treatment ◽  
High Grade ◽  
Sand Production ◽  
Worst Case ◽  
Carrier Fluid ◽  
Sand Control ◽  
Gravel Pack

Abstract In unconsolidated sand reservoirs, proper sand control completion methods are necessary to help prevent reservoir sand production. Failure due to sand production from surface equipment damage to downhole equipment failures which can ultimately result in loss of well integrity and worst-case catastrophic failure. Gravel Packing is currently the most widely used sand control method for controlling sand production in the oil and gas industry to deliver a proppant filter in the annular space between an unconsolidated formation and a centralized integrated screen in front of target zones. Additional mechanical skin and proper proppant packing downhole are the most critical objective when implementing gravel packs as part of a completion operation. This paper presents a case history of Well SX that was designed as single-trip multi-zone completion 7-inch casing, S-shape well type, having 86 deg inclination along 1300 meters, 4 to 5-meter perforation range interval and 54 deg inclination in front of the reservoir with total depth of 3800 mMD. The well consists of 4 zones of interest which had previously been treated with a two-trip gravel pack system. While Well NX was designed as single-trip multi-zone completion in 7-inch casing, J-shape well type, 8-meter perforation interval and 84 deg inclination in front of the reservoir with total depth of 3300 mMD. The well consists of two zones of interest which had previously been treated with a single-trip gravel pack system. Both wells are in the Sisi-Nubi field offshore Mahakam on East Kalimantan Province of Borneo, Indonesia. This paper discusses the downhole completion design and operation as well as the changes to the gravel pack carrier which overcame challenges such as high friction in the 7" lower completion and the potential for an improper annular gravel pack due to the lack of shunt tubes in a highly deviated wellbore. In vertical wellbores, obtaining a complete annular pack is relatively easy to accomplish but in highly deviated wellbores, the annular gravel pack is more difficult to achieve and can contribute additional skin. Tibbles at al (2007) noted that installing a conventional gravel pack could result in skin values of 40 to 50, mostly due to poor proppant packing in perforation tunnels. Therefore, operator required to find a reliable gravel pack carrier fluid optimization for typical highly deviated wells to overcome the potential sand production issues by applying a single-trip multi-zone sand control system across both zones (without shunt tubes) along with the utilization of a high-grade xanthan biopolymer gravel pack carrier fluid. Laboratory testing was conducted to ensure that the gravel pack fluid could transport the sand to the sand control completion, large enough to allow for a complete annular pack and still allow the excess slurry to be circulated out of the hole. Electronic gravel pack simulations were performed to ensure that rate/pressure/sand concentration would allow for a complete gravel pack. All four zones in Both of Well SX and NX were successfully gravel packed with a high rate, relatively high sand concentration slurry. The well has not exhibited any sand production issues to date. The current production from both wells is above expectation and are comingled from the two primary zones. Multiple factors were considered during the design and operation of the sand control treatment. Those factors will be described in this paper, starting with candidate selection, completion strategy, operational challenges and treatment execution along with production monitoring of the well.

scholarly journals Laboratory Investigation on Optimum Selection of a Sand Control Method for an Interbedded Sandstone and Mudstone Reservoir

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-10
Author(s):  
Shaofeng Hu ◽  
Lihua Wang ◽  
Yishan Lou ◽  
Yanfeng Cao ◽  
Wenbo Meng ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Control Method ◽  
Experimental Studies ◽  
Control Design ◽  
Gas Production ◽  
Control Mode ◽  
Critical Parameters ◽  
Bohai Bay ◽  
Sand Production ◽  
Sand Control

It is critical to select an optimized sand control method for an interbedded sandstone and mudstone reservoir (ISMR) due to its serious sand production hazards. However, currently, most general sand control methods cannot meet the requirements of sand control in interbedded sandstone and mudstone reservoirs (e.g., Bohai Bay oil and gas fields from China). Ensuring efficiency of sand control and increasing the oil and gas production rate in this interbedded sandstone and mudstone become more and more important. In this paper, a “multilayer rotatable sand control experimental device” for the interbedded sandstone and mudstone reservoir was developed. A series of sand control experimental studies were conducted by using the proposed device. The net-to-gross ratio (NTG) and well inclinations are two major factors considered in the experimental analysis. In addition, a sensitivity analysis regarding formation particle size distribution (PSD), clay content, and mineral compositions is performed in the experiment under a moderate sand control mode. With systematic experimental test results in this work, combined with numerous existing sand control models, a set of optimum sand control design and the associated optimization template for ISMR were developed, which have been successfully applied in Bohai Bay. Field application results show that NTG and well inclination are two critical parameters in the design of sand control in ISMR. The optimal indexes of a sand control mode are determined as NTG of 0.4 and well inclination of 45°. The introduction of these two key factors in sand control design broadens the application range of moderate sand production.

Sand Free Production Success Through Proven Technology Enabler from An Untapped Heterogeneous Reservoir Zone Utilizing Gravel Pack Replacement Methodology

2020 ◽  
Author(s):  
Y. Anggoro
Keyword(s):  
Oil And Gas ◽  
Erosion Resistance ◽  
Cost Effective ◽  
High Rate ◽  
Screen Design ◽  
Sand Control ◽  
Rules Of Thumb ◽  
Production Success ◽  
Control Technologies ◽  
Gravel Pack

The Belida field is an offshore field located in Block B of Indonesia’s South Natuna Sea. This field was discovered in 1989. Both oil and gas bearing reservoirs are present in the Belida field in the Miocene Arang, Udang and Intra Barat Formations. Within the middle Arang Formation, there are three gas pay zones informally referred to as Beta, Gamma and Delta. These sand zones are thin pay zones which need to be carefully planned and economically exploited. Due to the nature of the reservoir, sand production is a challenge and requires downhole sand control. A key challenge for sand control equipment in this application is erosion resistance without inhibiting productivity as high gas rates and associated high flow velocity is expected from the zones, which is known to have caused sand control failure. To help achieve a cost-effective and easily planned deployment solution to produce hydrocarbons, a rigless deployment is the preferred method to deploy downhole sand control. PSD analysis from the reservoir zone suggested from ‘Industry Rules of Thumb’ a conventional gravel pack deployment as a means of downhole sand control. However, based on review of newer globally proven sand control technologies since adoption of these ‘Industry Rules of Thumb’, a cost-effective solution could be considered and implemented utilizing Ceramic Sand Screen technology. This paper will discuss the successful application at Block B, Natuna Sea using Ceramic Sand Screens as a rigless intervention solution addressing the erosion / hot spotting challenges in these high rate production zones. The erosion resistance of the Ceramic Sand Screen design allows a deployment methodology directly adjacent to the perforated interval to resist against premature loss of sand control. The robust ceramic screen design gave the flexibility required to develop a cost-effective lower completion deployment methodology both from a challenging make up in the well due to a restrictive lubricator length to the tractor conveyancing in the well to land out at the desired set depth covering the producing zone. The paper will overview the success of multi-service and product supply co-operation adopting technology enablers to challenge ‘Industry Rules of Thumb’ replaced by rigless reasoning as a standard well intervention downhole sand control solution where Medco E&P Natuna Ltd. (Medco E&P) faces sand control challenges in their high deviation, sidetracked well stock. The paper draws final attention to the hydrocarbon performance gain resulting due to the ability for choke free production to allow drawing down the well at higher rates than initially expected from this zone.

scholarly journals A robust fuzzy logic-based model for predicting the critical total drawdown in sand production in oil and gas wells

PLoS ONE ◽  
2021 ◽  
Vol 16 (4) ◽  
pp. e0250466
Author(s):  
Fahd Saeed Alakbari ◽  
Mysara Eissa Mohyaldinn ◽  
Mohammed Abdalla Ayoub ◽  
Ali Samer Muhsan ◽  
Ibnelwaleed A. Hussein
Keyword(s):  
Fuzzy Logic ◽  
Correlation Coefficient ◽  
Oil And Gas ◽  
Maximum Error ◽  
Physical Parameters ◽  
Sand Production ◽  
Gas Reservoirs ◽  
The North ◽  
Sand Control ◽  
North Adriatic Sea

Sand management is essential for enhancing the production in oil and gas reservoirs. The critical total drawdown (CTD) is used as a reliable indicator of the onset of sand production; hence, its accurate prediction is very important. There are many published CTD prediction correlations in literature. However, the accuracy of most of these models is questionable. Therefore, further improvement in CTD prediction is needed for more effective and successful sand control. This article presents a robust and accurate fuzzy logic (FL) model for predicting the CTD. Literature on 23 wells of the North Adriatic Sea was used to develop the model. The used data were split into 70% training sets and 30% testing sets. Trend analysis was conducted to verify that the developed model follows the correct physical behavior trends of the input parameters. Some statistical analyses were performed to check the model’s reliability and accuracy as compared to the published correlations. The results demonstrated that the proposed FL model substantially outperforms the current published correlations and shows higher prediction accuracy. These results were verified using the highest correlation coefficient, the lowest average absolute percent relative error (AAPRE), the lowest maximum error (max. AAPRE), the lowest standard deviation (SD), and the lowest root mean square error (RMSE). Results showed that the lowest AAPRE is 8.6%, whereas the highest correlation coefficient is 0.9947. These values of AAPRE (<10%) indicate that the FL model could predicts the CTD more accurately than other published models (>20% AAPRE). Moreover, further analysis indicated the robustness of the FL model, because it follows the trends of all physical parameters affecting the CTD.

Numerical Investigation of Sand-Screen Performance in the Presence of Adhesive Effects for Enhanced Sand Control

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2195-2208 ◽  
Author(s):  
Siti Nur Shaffee ◽  
Paul F. Luckham ◽  
Omar K. Matar ◽  
Aditya Karnik ◽  
Mohd Shahrul Zamberi
Keyword(s):  
Management Practices ◽  
Oil And Gas ◽  
Voronoi Tessellation ◽  
Oil And Gas Industry ◽  
Solid Particles ◽  
Particle Adhesion ◽  
Sand Production ◽  
Gas Industry ◽  
Particle Filtration ◽  
Sand Control

Summary In many industrial processes, an effective particle–filtration system is essential for removing unwanted solids. The oil and gas industry has explored various technologies to control and manage excessive sand production, such as by installing sand screens or injecting consolidation chemicals in sand–prone wells as part of sand–management practices. However, for an unconsolidated sandstone formation, the selection and design of effective sand control remains a challenge. In recent years, the use of a computational technique known as the discrete–element method (DEM) has been explored to gain insight into the various parameters affecting sand–screen–retention behavior and the optimization of various types of sand screens (Mondal et al. 2011, 2012, 2016; Feng et al. 2012; Wu et al. 2016). In this paper, we investigate the effectiveness of particle filtration using a fully coupled computational–fluid–dynamics (CFD)/DEM approach featuring polydispersed, adhesive solid particles. We found that an increase in particle adhesion reduces the amount of solid in the liquid filtrate that passes through the opening of a wire–wrapped screen, and that a solid pack of particle agglomerates is formed over the screen with time. We also determined that increasing particle adhesion gives rise to a decrease in packing density and a diminished pressure drop across the solid pack covering the screen. This finding is further supported by a Voronoi tessellation analysis, which reveals an increase in porosity of the solid pack with elevated particle adhesion. The results of this study demonstrate that increasing the level of particle agglomeration, such as by using an adhesion–promoting chemical additive, has beneficial effects on particle filtration. An important application of these findings is the design and optimization of sand–control processes for a hydrocarbon well with excessive sand production, which is a major challenge in the oil and gas industry.

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

2022 ◽  
Vol 10 (1) ◽  
pp. 71
Author(s):  
Yiqun Zhang ◽  
Wei Wang ◽  
Panpan Zhang ◽  
Gensheng Li ◽  
Shouceng Tian ◽  
...  
Keyword(s):  
Natural Gas ◽  
Gas Hydrate ◽  
Control Method ◽  
Gas Production ◽  
Sand Production ◽  
Natural Gas Hydrate ◽  
Vertical Well ◽  
Sand Control ◽  
Gravel Packing ◽  
Radial Well

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

Chemical Sand Consolidation and Agglomeration Control Sand Production

2021 ◽  
Vol 73 (10) ◽  
pp. 73-74
Author(s):  
Chris Carpenter
Keyword(s):  
Success Rate ◽  
Oil And Gas ◽  
Lessons Learned ◽  
Asia Pacific ◽  
Interval Length ◽  
Sand Production ◽  
Chemical Application ◽  
Placement Method ◽  
Sand Control ◽  
Production Period

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202419, “Performance Review of Chemical Sand Consolidation and Agglomeration for Maximum Potential as Downhole Sand Control: An Operator’s Experience,” by Nur Atiqah Hassan, SPE, Wei Jian Yeap, SPE, and Ratan Singh, Petronas, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Chemical sand consolidation (SCON) and sand agglomeration have been identified as effective chemical treatments to control sand production downhole. Both treatments involve injection of chemicals into the near-wellbore area of the reservoir with the aim of improving the strength of the formation and thus reducing the tendency for sand production. The complete paper presents lessons learned and best practices from several chemical SCON and sand-agglomeration treatments performed in mature fields in Malaysia. SCON and Sand Agglomeration History and Performance Petronas has deployed approximately 20 SCON and three sand-agglomeration treatments over nine different offshore fields since 2009. Of 20 planned SCON jobs, four were suspended for a variety of reasons such as budget constraints or operational complexity. Of the 16 SCON jobs executed, a success rate of approximately 75% was achieved. The number of sand agglomeration jobs executed is significantly lower; only three were completed, with one failure case. In terms of effective production, SCON has better overall performance than sand agglomeration. The average effective production period for SCON is approximately 2.9 years, while the average effective production period for sand agglomeration is approximately 2.5 years. Criteria for Candidate Selection Completion Type. - In considering the historical success rate of SCON and sand-agglomeration jobs according to completion type, most viable candidates were completed with perforated cased hole, contributing to approximately 87% of all chemical SCON and sand-agglomeration jobs. Despite the challenges caused by chemical placement in openhole completions, all of these jobs have been successful because of stringent planning. Overall, the success rate for chemical SCON and agglomeration under cased-hole completion is approximately 73%. Perforation Interval Length. - For effective chemical placement, the perforation interval length is limited to 20 ft according to internal guidelines, especially for cases using bullheading as the placement method. For perforation interval lengths greater than 120 ft, the failure rate can be as high as 10%. According to historical trends, no failure was encountered for chemical SCON and sand-agglomeration jobs with perforation intervals of less than 40 ft. The historical analysis indicates, therefore, that the benchmark criteria of perforation interval length could be extended to 40 ft from the current 20 ft. Placement Method. - Most chemical treatment jobs executed were completed using bullheading, contributing to approximately 80% of all chemical SCON and sand-agglomeration jobs. No failure cases were recorded for treatments that used coiled tubing because of the controlled chemical placement. Perforation intervals of almost 100 ft using bullheading placement methods have succeeded. One contributing factor for successful treatment in long intervals using bullheading is the use of diversion techniques. Nitrogen is commonly used as part of a diversion method along with chemical application.

Lessons Learned from the First Chemical Sand Consolidation in Zawtika Field

2021 ◽  
Author(s):  
Wiwat Wiwatanapataphee ◽  
Thanita Kiatrabile ◽  
Pipat Lilaprathuang ◽  
Noppanan Nopsiri ◽  
Panyawadee Kritsanamontri
Keyword(s):  
Control Method ◽  
Cost Effective ◽  
Lessons Learned ◽  
Candidate Selection ◽  
High Rate ◽  
Operation Performance ◽  
Coiled Tubing ◽  
Cost Effective Method ◽  
Sand Control ◽  
Gravel Pack

Abstract The conventional gravel pack sand control completion (High Rate Water Pack / Extension Pack) was the primary sand control method for PTTEPI, Myanmar Zawtika field since 2014 for more than 80 wells. Although the completion cost of gravel pack sand control was dramatically reduced around 75 percent due to the operation performance improvement along 5 years, the further cost reduction still mandatory to make the future development phase feasible. In order to tackle the well economy challenge, several alternative sand control completion designs were reviewed with the existing Zawtika subsurface information. The Chemical Sand Consolidation (CSC) or resin which is cost-effective method to control the sand production with injected chemicals is selected to be tested in 3 candidate wells. Therefore, the first trial campaign of CSC was performed with the Coiled Tubing Unit (CTU) in March to May 2019 with positive campaign results. The operation program and lesson learned were captured in this paper for future improvement in term of well candidate selection, operation planning and execution. The three monobore completion wells were treated with the CSC. The results positively showed that the higher sand-free rates can be achieved. The operation steps consist of 1) Perform sand cleanout to existing perforation interval or perforate the new formation interval. 2) Pumping pre-flush chemical to conditioning the formation to accept the resin 3) Pumping resin to coating on formation grain sand 4) Pumping the post-flush chemical to remove an excess resin from sand 5) Shut in the well to wait for resin curing before open back to production. However, throughout the campaign, there were several lessons learned, which will be required for future cost and time optimization. In operational view, the proper candidate selection shall avoid operational difficulties e.g. available rathole. As well, detailed operation plan and job design will result in effective CSC jobs. For instance, the coil tubing packer is suggested for better resin placement in the formation. Moreover, accommodation arrangement (either barge or additional vessel) and logistics management still have room for improvement. These 3 wells are the evidences of the successful applications in Zawtika field. With good planning, lesson learned and further optimization, this CSC method can be beneficial for existing monobore wells, which required sand control and also will be the alternative sand control method for upcoming development phases. This CSC will be able to increase project economic and also unlock the marginal reservoirs those will not justify the higher cost of conventional gravel pack.

Redefining Fracpack For Sand And Fines Control Completion in 30 Years Old Producing Field

2021 ◽  
Author(s):  
Jagaan Selladurai ◽  
Cheol Hwan Roh ◽  
Amr Zeidan ◽  
Saurabh Anand ◽  
Bahrom Madon ◽  
...  
Keyword(s):  
Control Method ◽  
Movement Control ◽  
Work Flow ◽  
New Approach ◽  
Sand Control ◽  
Net Pressure ◽  
Ultimate Objective ◽  
Clastic Reservoirs ◽  
Gravel Pack

Abstract Malaysian clastic reservoirs are plagued with high fines content which rapidly deteriorates the productivity from wells completed with conventional form of sand control techniques. To mitigate the fines production issue, Petronas recently successfully completed 3 reservoirs in two wells in Field-D using enhanced gravel pack technique. This paper explains in detail the workflow, challenges such as depleted reservoirs, coal streaks, and nearby water contacts and operational execution for the successful re-defined extension pack jobs. This new approach consists of a re-defined Extension Pack / Frac Pack job with fine movement control resin and a re-defined perforation strategy. Perforation strategy consists of limited number of 180 deg phasing non-oriented perforations done under dynamic underbalance conditions. The key requirement to have fracturing as a sand control method is to have a tip screen out (TSO) or high net pressure placement to ensure the fracture has good conductivity. To obtain a good TSO, data acquisition is of paramount importance. The fracturing jobs in the Field – D wells were preceded with step-rate tests, injection tests, minifrac and Diagnostic Fracture Injection Test (DFIT). The data from diagnostic tests were used diligently to have best possible fracturing treatment in the target zones. Excellent pack factors of greater than 500 lbs. per ft were obtained for all the treatment jobs using only linear gel with proppant concentration up to 7 ppa. This high pack factor translates to very good frac conductivity which is essential in fracturing for sand control. Some of the fracturing treatments concluded with a TSO signature which is a big achievement considering the challenges that were associated with fracturing in Field – D. In addition, DFIT and ACA (After Closure Analysis) was performed to estimate permeability and results were compared with various techniques such as log derived and formation tester permeability. Ultimate objective from this analysis is to have a work-flow which can screen candidate wells for such treatments from openhole logs and give an estimated liquid rate post treatment. Also, the workflow for planning and executing fracturing jobs will be presented for Malaysian clastic reservoirs. This work-flow will be vetted against the extensive diagnostic and fracturing data that has been acquired during fracturing treatments in Field – D. Design, actual diagnostic, and fracturing data will be presented in this paper. It is expected that this modified form of sand and fines control will help in reducing the fines issue in Field – D to a great extent along with expected incremental in oil production. If long term production sustainability is proven, similar approach will be adopted by Petronas and can be shared amongst other South East Asia operators in many similar other fields.

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