This paper will discuss the case study of two (2) projects in Malaysia that were stretched-to-limit and optimized ‘on-paper’ all the wells’ related engineering design and construction, operation activities pre and during drilling campaign as well as logistic arrangement, which led to significant cost reduction in wells and thus improving the overall project economics. This significant savings achieved with full compliance to technical standards as well as with the betterment to improve HSE during offshore execution.

Lost circulation is a complicated situation in the drilling operation, wasting a lot of time and mud during processing. A serious lost circulation can cause hazards, such as sticking, blowout and collapse of well. There are some problems in conventional plugging technology, such as particle size of plugging material does not match crack width, slip of the blocking zone, and weak adhesion of lost circulation additive to the rock, which restricts the success rate of lost circulation operation. Regular and elastic polyhedron structure material compounds elastic variable network plugging material and rigid plugging materials to form a loss circulation materials (LCM)plugging mixture for different leakage speed and crack width affected by stress. Through plugging and HTHP sand bed experiment loss circulation materials(LCM) and amount of gel were optimized and improved. Through indoor simulation about leakage process of different leakage speed and different crack sizes, the on-site construction formula suitable for wells under different temperature is formed and determined. Scanning electron microscope shows the plugging gel has a variable network structure. By changing the ratio of elastic plugging material, rigid plugging material and gel, a LCM plugging formula for high temperature and high pressure formations can be formed to meet the pressure requirement of 7.5MPa. Leakage simulation formed on-site plan under different leakage rate to adapt to 180°C. The novel CPM material has been well-field tested and used for HPHT reservoirs. When the rate of leakage less than 30 m 3 /h and 30-60 m 3 /h, success rate of single plugging is more than 95% and rate of leakage greater than 60 m 3 /h success rate of single plugging beyond 80%. Leakage loss time is more than 80% shorter than conventional plugging techniques.

Cyclonic devices are ubiquitous in industrial processes and have been used for particle separation for decades. However, designing a highly efficient, compact cyclone for erratic flow conditions and particles of varying types, sizes and density remains a challenge. This paper aims to present the challenges, lessons learnt and recent development in cyclone technology for solid separation. Primarily, a discussion on typical cyclonic desander geometries is conducted. Failures and sub-optimal operation of cyclonic wellhead desanders within the company are analysed, and subsequently the failure mechanisms and factors leading to inefficiencies are identified. Computational Fluid Dynamics (CFD) simulations and flow loop testing are further performed to verify the particle separation efficiency and quantify the erosion risks of the typical cyclone geometries. The typical cyclonic geometries are considerably less efficient in multiphase-flows compared to the gas-solid or liquid-solid flows. As a result, the overflow section of the cyclone often contains particles larger than the design specification. Changing operating envelope over time, for example, reducing production and changing flow regime affects cyclone efficiency over time. Based on a systematic analysis of the desander failures in the fields, a few design improvements have been proposed to overcome these limitations, resulting in a novel technology. This new cyclonic technology with multiple barrier system can successfully maintain the 98% target removal of 10microns particle under erratic multiphase-flows conditions. Furthermore, it can be designed to handle various types of particles e.g., sands, HgS and other solids. The versatility of this system provides promising technology for ageing fields with excessive solids production.

The use of micronized weighting agents, in multiple operations, have become more commonplace over the years, with current applications now going far beyond their targeted original purpose of reducing pressure losses in extended reach wells. This specific case reports the development of a fit for purpose system engineered to tackle multiple challenges such as: limitation in using heavy density brines composed of bromides in an offshore environment; hydrate suppression under Drill Stem Test (DST) conditions; weighting agent sagging control; plugging of downhole tools due to heavy solids loading; proper pressure transmission for downhole tools activation; and formation damage prevention. The operation involved the following steps: 1 - development of a Water-based Micronized Weighting Agent Fluid System (WBMWAFS), laboratory testing, simulation evaluation and testing validation for all target properties; 2 - development of an appropriate DST approach with the usage of a designed set of explosives to minimize formation damage and the interaction of the DST fluid with such cargos; and 3 - the evaluation of the overall system performance in order to validate the integrated approach used to design such solution. The DST results indicated that the WBMWAFS is capable of delivering all the technical requirements for a trouble-free operation, with no significant register of weighting agent sag, hydrates or with any variation in fluid properties, whilst enabling a DST operation that demonstrated a negative skin damage during the clean-up period and no damage associated with the WBMWAFS. The WBMWAFS performance opens the possibility of the application of this type of fluid as a replacement for high-density clear brines in many challenging environments.

The Comalcalco Fault is a regional discontinuity that can present highly unstable zones when crossing it or its influence zone. This instability can lead to notorious increase in drag forces, cavings, stuck pipe events and ultimately loss of sections or the well. In the 12 ¼" hole of this exploratory well, this fault was present and despite some of the wells in the field managed to cross it without consequences, the influence was more notorious, and the problems lead to catastrophic results. While drilling the 12 ¼" section, the team was able to drill up to 4368 m without any relevant problems. The fault was intersected and drilled pass to section TD with the previous casing shoe at 2966 m. However, when a trip to surface was necessary, abnormal drag forces that avoided further movement of the string were experienced. This event led to the loss of the section and the need to perform a sidetrack, right across the influence zone of the fault at 3200 m. The risk was reassessed, and numerous preventive and mitigation measures were put in place, including drilling the section with a 12 ¼" pilot bit, enlarging the pilot hole to 13 ½" to cover the influence zone and having a contingency plan to run the 11 ¾" liner. Additionally, the formations were reinforced through drilling fluids design, and drilling and tripping strategies were optimized to minimize zonal invasion and influence zone disturbances that could lead to additional cavings. After the successful sidetrack, the section was drilled to 3600 m, 200 m below the fault’s influence zone. Good ROPs and low levels of stick and slip were observed despite several reaming runs while drilling. The contingency liner was run to TD, achieving the objective of isolating the influence zone of the Comalcalco Fault. With the problematic zone placed behind pipes, drilling the remaining of the original 12 ¼" sections with a 10 5/8" × 12 ¼" reamer resulted in the longest and fastest enlarged section to be realized in the field. With all the preventive measures put in place, the original 9 5/8" casing was set at its planned depth, avoiding an additional casing string and a change of the design of the completion.

Monobore cementation is defined as where a single production tubing size runs from the pay zone all the way to surface and is cemented in place. This type of well design greatly reduce rig time and cost. The challenge however is to achieve a good cement in the annulus as a well barrier and to have a clean internal tubing after the cementing job to allow for successful production of the well. To achieve a clean internal tubing, a distinct bottom and top plugs were used as a means of mechanical separation. For fluids design, mud had to be thinned down prior to the cementing job and, a designed fiber based spacer system was used to physically scrub any mud-film sticking on the tubing walls. The centralizers and cement system were designed to allow for efficient displacement of mud and hence providing good overall placement and top of cement in the tubing-casing annulus. The cement in the annulus will be verified by pressure testing the annulus to 500 psi higher than previous shoe leak-off. This approach was implemented for the campaign of six wells, all designed with 5-1/2in monobore tubing. The bottomhole static temperature (BHST) of the well ranges from 300 to 350°F. The cementing system also had to be designed to cater to the challenge of this field, having CO2 as high as 60%, high temperatures, and a long open hole section that requires isolation and cement to set within a required timeframe. The cementing jobs were validated by no losses or gains during the job, floats holding at the end of the cementing job, differential pressure of cement prior to bumping the plug, density and pump rates executed as planned, accepted pressure test criteria of the annulus, output validation of cement contamination in pipe and annulus based on fluids and final well information. To further validate this system, the cement bond log was also run as part of the evaluation process and the cement log showed that zonal isolation was achieved. After the perforations, the perforation tool was pulled out to surface and the tool looked very clean with no signs of contaminated mud or cement around the tool. We demonstrate how this unique cementing approach can be a solution for the challenges of monobore cementing and one of the biggest problems of monobore cementing in the industry.

This paper will detail the engineering strategies utilized from design and planning stage up to and beyond the field execution stage which resulted in drilling the fastest well in a shallow water field, delivering superior drilling performance and successfully targeting the Upper Miocene (tertiary) reservoir in Mexico. From the 9 wells drilled in this field, the fastest well "Y"-200 was drilled with an average well construction index of 179 m/day when compared to the field average of 54.2 m/day. This shallow water field manifests several specific challenges which include tough drilling conditions, fluid property and hydraulic management, logging constraints and critical selection of casing setting depths. In order to enhance the drilling performance results to lower costs and improve production timelines, the project team performed a deep-dive into the well challenges and engaged with multi disciplinary teams and service providers to brainstorm different design improvements and operational practices. By doing so, the performance accelerates the 6000 to 9000 bbls of initial production estimated per well. The application of these creative engineering ideas proves that change, when applied correctly can really create lasting and proven improvements in drilling performance.

This paper presents a method of reducing equivalent circulating density (ECD) while drilling using eccentric string reamers (ESR) with adjustable gage stabilizer (AGS) in Gulf of Thailand (GoT). Reduced ECD in slimhole is desirable when drilling depleted reservoirs as reduced borehole pressure can reduce or delay drilling fluid loss events. Delaying losses can allow well depth to be increased with the prospect of penetrating otherwise unrealized pay horizons and increasing reserves capture. Several methods of reducing ECD were considered but most solutions included changing drill string and/or casing design specifications with prohibitive cost. A low-cost, low operational-impact solution was needed. Hole-opening is a method of increasing annular clearance, but well delivery requirements of ~4.5 days per well necessitates a one-trip solution without introducing significant ROP reduction or negatively impact bottomhole assembly (BHA) walking tendencies. Further, the preferred solution must be compatible with a high temperature reservoir drilling environment and must not undermine drilling system operational reliability. A simple but controversial tool for hole opening is ESR. ESR’s are simple in that there are no moving parts or cutter blocks to shift, and operating cost is low. They are controversial due to uncertainty that the tool eccentricity and drilling dynamics will successfully open hole to the desired diameter. Given that the intent of this hole-opening application is limited to creating annular clearance for fluid, not mechanical clearance, the eccentric reamer solution was chosen for field trial and potential development. A tool design challenge was to create a reamer geometry with the desired enlargement ratio (6⅛-in. to 6⅞-in.) while drilling, and reliably drift surface equipment and casing without complications. The ESR design must efficiently drill-out cement and float equipment as well as heterogeneous shale/sand/mudstone interbedded formation layers without significant vibration. If successful, the enlarged hole diameter will increase annular clearance, reduce ECD, improve hole cleaning, and allow drilling depth to be increased to capture additional reserves The plug and play functionality of the ESR required no changes to the existing rig site procedures in handling and making up the tool. The ESR drifts the casing and drills cement and shoe track with normal parameters. The ESR is run with standard measurements-while-drilling (MWD)/logging-while-drilling (LWD) AGS BHA and is able to reduce ECD providing the opportunity to drill deeper and increase barrel of oil equivalent (BOE) per each wellbore. Performance analysis has shown no negative effect on drilling performance and BHA walking tendency. The novelty of this ESR application is its proven ability to assist in increasing reserves capture in highly depleted reservoirs. The ESR is performing very efficiently (high ROP) and reliability is outstanding. In this application, the ESR is a very cost-effective and viable solution for slimhole design.

Lost circulation while drilling across vugular or naturally fractured formations is a difficult challenge which will come with high cost for the oil and gas industry. When lost circulation encounter, the drilling company will result in nonproductive time and remedial operational expenses. Most of the fields in UAE are encountering lost circulation problems while drilling across surface sections, which are difficult to control with conventional lost circulation solutions. Newly engineered high-performance lightweight thixotropic proves beneficial to control losses in vugular and natural fractured formations. The main challenge while drilling the surface section in one UAE field is the total loss of returns and flowing formation. This leads to the inability to continue drilling due logistics to continue producing drilling fluid and to keep the well under control and risk of stuck pipe due to poor cuttings removal. Conventional low-density cement slurries have been widely used to cure losses while drilling, but with low effectiveness. A new lost circulation solution that combines lightweight (10.5–lbm/galUS) high-performance cement and a thixotropic agent produce an engineered high-performance lightweight thixotropic lost circulation solution with fast gel strength and improved compressive strength, enabling the plugging of large voids and fractures to recovery wellbore integrity required to continue drilling. Extensive laboratory qualification tests were performed for static gel strength development to confirm the plugging efficiency and compressive strength development. The results were promising with more than 110 lbf/100 ft 2 of static gel strength in 10 minutes and compressive strength development of 1,000 psi within 24 hours at low surface temperature. In addition, a transition time (TT) with on-off-on test demonstrated more faster gel strength development was developed when the reduction of the shear rate and regained pumpable with reapplication of shear. In one of the wells, total losses were encountered while drilling across surface section. The lightweight high-performance thixotropic solution was pumped for the first time worldwide, proved that the innovative lost circulation solution was effective in curing the losses, and enabled the operator to continue drilling the section to TD. This case study demonstrates that the engineered system is effective in curing losses and reducing nonproductive time. The unique properties of more faster gel strength and enhanced compressive strength make this system more effective for treating a different types of lost circulation scenarios during drilling ( Jadhav and Patil, 2018 ). New high-performance lightweight thixotropic cement lost circulation solution exhibits strong performance in curing total losses and establishing well integrity with reliability.

Foam fracturing is an effective method for the development of unconventional reservoirs. However, due to lamellar film, high pressure differences within foam films, and the strong diffusivity of the internal phase, foam is prone to suffering from unstable phenomena such as rupture, drainage, disproportionation, etc., thus leading to uncontrollable foam flow behavior in the tube and formation. In this work, cellulose nanofibrils (CNFs) were used to enhance foam fracturing fluid. The target is not only to obtain a stable foam system, but also to control its rheology, proppant-carrying and leak-off behavior. The stability of the N 2 foam fracturing fluid with CNFs was firstly explored via static tests by measuring its foam volume and liquid drainage. Then, the viscosity of foam fracturing fluids with different foam quality was measured using a tube viscometer under conditions of use, to evaluate the rheology of foam with CNFs. Subsequently, the proppant-carrying capacity was evaluated by observing suspension state of proppants in foam over time. The microscopic images of the foam with proppants were collected to analyze the interaction between bubbles and proppant. Finally, the dynamic filtration behavior and core damage of foam with CNFs were investigated by using a dynamic filtration apparatus. The results of the static tests showed that the stability of foam was significantly enhanced by the addition of CNFs, and the liquid drainage and gas diffusion could be effectively inhibited. Upon foam evolution, bare surfactant foam formed a polyhedral structure rapidly, while the CNFs enhanced foam maintained spherical and dense for a long time. The viscosity of foams with and without cellulose nanofibrils showed a shear thinning behavior. With the addition of CNFs, the viscosity of foam was improved by 3 - 6 times compared with bare surfactant foam and its value was increased with foam quality changing from 60% to 80%. The results of proppant-carrying tests indicated that the proppants suspension in foam was improved obviously as the cellulose nanofibrils were added. For CNFs-stabilized foam, the aqueous film of bubbles became thicker and the mechanical strength of foam structure was improved, thus enhancing the proppant suspension in the foams. Moreover, the filtration control performance of CNFs foam was also improved compared with bare surfactant foam. The filtration coefficient of CNFs foam fracturing fluid decreased with increasing CNFs concentration at a filtration pressure difference of 3 MPa, and core damage was maintained at a relatively low level. Additionally, the filtration coefficient of CNFs-stabilized foam and its core damage could be reduced with the increase of foam quality from 60% to 80%. The stability, rheology, proppant-carrying and dynamic filtration control of foam fracturing fluid enhanced by cellulose nanofibrils were explored in this work. The results show that the addition of CNFs effectively improves the stability of the foam, thus enabling the rheology, proppant-carrying and the dynamic filtration to be well controlled, which provides a high-performance and eco-friendly foam fracturing fluid.

There are many challenges while drilling highly inclined and depleted formations offshore Vietnam that result in various wellbore stability issues such as severe losses, stuck pipe, cavings, tight-hole and pack-offs. These issues may be independent of mud type and can occur when drilling with both oil/synthetic-based and water-based muds. These depleted sections typically consist of sandstones interbedded with claystone & siltstones. Traditionally, the wellbore strengthening fluids solution applied to drill through these sections with synthetic and water-based mud in Vietnam faced limited success. Wellbore strengthening (WBS) is a proven and effective solution especially for narrow-drilling margin and depleted formations. The basic concept of WBS relies on the creation and simultaneous plugging of small fractures with appropriate WBS material. The resulting elevated stress around the wellbore strengthens the borehole by creating an increased hoop stress that leads to an increase in near wellbore stresses. Proprietary modelling software can be used to calculate the pressure induced fracture apertures for wellbore strengthening applications and determine the optimum particle size range to bridge these fractures, allowing fluids to be designed to minimise wellbore instability. This design process was used to optimize material additives to effectively bridge fractures, for wellbore strengthening, and pore throat openings in porous/permeable formations for the prevention of seepage losses and differential sticking. A review of the application procedure identified the optimum method to apply the wellbore strengthening material which would minimise product consumption and reduce well costs. After extensive modelling simulations and testing, this fluid design was applied to drill two challenging wells in Vietnam. This paper presents the process of modelling, based on formation geo-mechanics information, customization and laboratory testing of the fluids design coupled with a successful and economical method of application in the field. Application of this process enabled the operator to drill through the depleted challenging sections with a maximum overbalance pressure of 3,200 psi, conduct logging and coring runs and complete the well at a lower cost and with zero fluids related non-productive time compared to previous wells.

This paper is to explain the optimization of using Modified Shale Inhibitor Water Based Mud (WBM) to drill up to 5,500 ft interval of K-formation reactive shale on South-S Gas Wells. By combining a comprehensive method consists of drilling fluid laboratory test and lessons learned in S area, the optimization was done by determining the amount or concentration of Polyamine & KCl combination, pure Polyamine, Polyamine & NaCl combination, and Pure KCl-Polymer in WBM system as a shale inhibitor. The comparison of shale inhibitor compositions were made by comparing the achieved optimization of drilling fluid program such as drilling time, cost economic, and environment aspect. The basic idea of the WBM optimization was to improve drilling time during drill 5,000 ft footage in 12-1/4" hole section in reactive shale formation as per drilling program. Laboratory test consists of Linear swelling meter with various parameter concentration of Polyamine & KCl combination, pure Polyamine, Polyamine & NACl combination, and Pure KCl-Polymer in WBM system as a shale inhibitor and cation exchange capacity test (CEC or MBT) was done using composite of offset well shale cutting. Experience showed that on 12-1/4" hole section, while facing reactive shale (CEC 18 - 24 meq/100 gr) from K-formation on South-S, modified WBM was proven to eliminate reactive shale issues and lead to budget saving without environmental issues.

Objective/Scope The objective of this paper is to highlight the fact that while in conventional drilling there can sometimes be no mud weight solution for drilling a particular narrow margin section without either exceeding the Leak Off Test value at the shoe, or falling below the Pore Pressure at section TD. In Managed Pressure Drilling (MPD) there is often a range of mud weight solutions that can be used to drill the section, but usually one optimum mud weight that should be used, based on different risk criteria that can be evaluated. The consequences of this are that when using MPD, it could be that the section risks have not been minimised and therefore more risk than necessary has been imported into the methodology. Whereas if all MPD mud weight solutions have been evaluated, together with their associated Surface Back Pressures, and the optimum selection made, then the mitigations can be specially tailored so that the remedial actions to any system failure are clearly planned in advance, reducing the overall risk level of the operation. Methods, Procedures, Process The methodology described in this paper demonstrates the process for choosing the optimal mud weight for drilling any well section using MPD, with worked examples. This process is especially applicable for drilling very narrow margin sections, for example with only 0.2 ppg window between Pore Pressure and Fracture Gradient. By enumerating the safety margins both at the previous casing shoe and at the proposed section TD, or any other point of interest, it is possible to rank the risks of kicks and losses in that section across a range of proposed mud weights and use this information to choose the optimal mud weight. Results, Observations, Conclusions The process of evaluating the options and outcomes of using different mud weights in MPD can not only lead to the best drilling solution for the section, but can also be used as a discussion tool between the drilling team and the subsurface team, to help elucidate the most likely risks to the operation and thereby mitigate those risks in the most appropriate way. Novel/Additive Information A further benefit of this approach is that the narrowest possible drilling windows can also be evaluated and as a result, options for extending TD and potentially eliminating casing strings can be considered, leading to considerable savings, which are highly prized at all times, but especially so in a low oil price environment.

Sludge formed downhole in the production interval can be classified into crude oil-based or mud-based sludge. Sludge obstruction may result in partial or total loss of well productivity. Oil-based mud is commonly used in drilling of the pay zones in sandstone formations as a less/non damaging fluid. Oil-based mud typically contain emulsifier, viscosifer and other additives including polymer blend and calcium carbonate to serve different functions. Presence of emulsifier may increase emulsion tendency upon interaction with downhole environment. The resulting emulsion might be tight to an extent that a thick sludge is formed which can impair well productivity. Similarly, oil-based sludge may form from oil/water interaction in presence of emulsifiers, asphaltene, wax, solids, shear, etc. Identification of the sludge material will help in development of an effective chemical treatment to remove formation damage and restore well productivity. In this study, an extensive laboratory work was conducted to explore potential interactions of different downhole environment contaminants/factors on formation of oil-based and mud-based sludge. Typical mud-based and crude oil-based sludge samples were characterized using different analytical techniques including solvent extraction, XRD, TGA, ICP and viscosity. The results showed that the mud-based sludge sample contained calcium carbonate, dolomite quartz as the main components in the inorganic phase while the organic phase include polymers and oil. The oil-based sludge sample contained mainly water (82 wt%) with some solid particulates and asphaltene in the organic phase. Analysis of supernatants generated from solubility tests conducted for the mud-based and oil-based sludge samples revealed in addition to the high amount of calcium presence of iron in considerable amount (nearly 1,000 mg/L). Interaction of ferric chloride, quartz with an invert-emulsion mud was investigated. A significant increase in viscosity was observed upon incorporation of these contaminates with the mud sample. Iron ions in the aqueous phase tended to stabilized emulsion. This paper presents in detail mechanisms of mud-based and crude oil-based sludge formation upon interaction with environment. It also examined several chemical formulations for removal of mud-based and oil-based sludge samples.

Malaysia's government recognizes the high risk that aging idle wells pose to its health, safety and environment and has developed some of the most stringent plug and abandonment, P&A, regulations to protect its future. Corroded casing strings and sustained casing pressure are common issues on its multi-decade old platforms and a risk-based design philosophy has been adopted to balance risk mitigation and operational costs, while still ensuring an eternal barrier. Both conventional rigs as well as rigless hydraulic workover units, HWU, are being used for P&A operations. This study considers the barrier element rationale applied in four offshore wells that were plug and abandoned by cap-rock restoration Perforate, Wash, Cement, PWC, barrier plugs. It also considers the operating window of a jet-based PWC technology to understand the challenges and opportunities for further optimization during HWU operations. Cap rock restoration utilizing both cup-based and jet-based PWC technology is being widely applied throughout Malaysia as a cost-effective alternative to casing section milled barrier plugs. Malaysia's P&A regulation allows isolation at the cap rock level, whereby "Contractor shall adhere to the Cap-Rock Abandonment Applicability Flowchart to identify technically and commercially acceptable candidates for this well abandonment method." The PWC method enables cap rock restoration in a single trip process; whereby the casing annulus is accessed by TCP guns to allow for annular debris to be effectively washed prior to cement plug placement. The process is not limited only to TCP guns; as a mechanical casing perforator was utilized in a shallow cased hole section of one of the wells to avoid damaging the outer casing. A custom BHA was developed and tested to match the cuts from the mechanical perforator. Specially oriented, rotating, wash jets were configured to maximize the annular access during the washing process. The washing effectiveness of this new BHA was confirmed by the massive amount of annular debris that was observed over the surface shakers. Operations were conducted offshore with a HWU with limited infrastructure and operating capability compared to a conventional rig. A PWC candidate screening matrix was applied early during the planning phase to manage rig limitation, well condition and operational risk to ensure successful barrier placement. All cap rock barriers were successfully installed and tested, and no sustained annular pressure remained in any of the wells. Fewer PWC plugs were required than originally planned, due to strict adherence to the Caprock Restoration Plan Decision Tree , resulting in significant cost savings for the project. The detailed time breakdown of the HWU operations provides useful insight into the operational efficiencies and unplanned events during the HWU campaign and lessons learned are shared from the project.

Lost circulation is the most common drilling issue for infill drilling projects in Satun-Funan Fields, South Pattani Basin, Gulf of Thailand (GOT). The depleted sand is possible to be a root cause in many wells based on observation from resistivity time-lapse separation in depleted sands or shale nearby. Therefore, the objective of this study is to estimate fracture pressure related to the depleted sand and design an appropriate Equivalent Circulating Density (ECD) threshold for each well to avoid or minimize lost circulation and well control complication during drilling a new well. This study model is using Eaton (1969) equation. There are 3 input parameters which are Poisson's Ratio and pre-drilled estimated depletion pressure and depth. With limitations of no actual fracturing data and limited sonic log, the maximum ECD while lost circulation reading from Pressure While Drilling (PWD) tool and formation pressure test data were used to back-calculate for Poisson's Ratio and identified a relationship with depth. From the total of 68 wells in the Satun and Funan areas, the interpreted Poisson's Ratio ranges from 0.36 to 0.44 and its linear trend is apparently increasing with depth. To minimize the variation of back calculated Poisson's Ratio the local data become an important key for model validation and maintain the similarity of subsurface factors. This interpreted Poisson's ratio trend will be used to calculate for fracture pressure by incorporating with estimated depletion pressure and depth that expect to encounter in each planned well. The lowest fracture pressure in a planned well is used to prepare pre-drilled ECD management plan and a real-time well monitoring plan. Additionally, the model can be adjusted during the operational phase based on the new drilled well result. This alternative model was applied in 4 trial drilling projects in 2019 and fully implement in 6 drilling projects in 2020. The lost circulation can be prevented with value creation from expected gain reserves section is $57M and cost avoidance from non-productive time due to lost circulation is $3.4M. With an effort, good communication and great collaboration among cross-functional teams, the model success rate increases by 12%. However, there are some unexpected lost events occurred even though the maximum ECD lower than expected fracture pressure. This suspect as a combination of limitations and uncertainties on key input parameters and drilling parameters. In the future, the model is planned to expand to other gas fields in the Pattani Basin which will move to more infill phase and have higher chance of getting lost circulation to maximize benefits as the success case in Satun and Funan fields.

With the development of new oil formations and with the advent of new directions in the global energy sector, new requirements for materials for well construction appear. With the close attention to environmental footprint and unique properties, one of the promising materials for well cementing is geopolymers. Being a relatively new material, they are characterized by low carbon footprint, high acid resistance and attractive mechanical properties. This article is aimed at developing new geopolymer slurries for the oil industry, their characterization and field implementation analysis. With the ultimate goal of developing a methodology for the analysis of raw materials and designing the geopolymer slurries, studies were carried out on various raw materials, including different types of fly ash. Based on the data obtained and rapid screening methods, an approach was developed to formulate a geopolymer composition recipe. Since not all cement additives directly work in geopolymers, special attention was paid to control the thickening time and fluid loss. The methods of XRD, XRF, ICP-MS, density, particle size distribution measurements as well as API methods of cement testing were used to understand the composition and structure of the materials obtained, their properties and design limitations. A special approach was applied to study the acid resistance of the materials obtained and to compare with conventional cements and slags. Using one of the most common sources of aluminosilicate, fly ash, formulations with a density of 13.5 – 16.5 lbm/galUS were tested. A sensitivity analysis showed that the type of activator and its composition play a critical role both in the mechanical properties of the final product and in the solidification time and rheological properties of the product. The use of several samples of fly ash, significantly different in composition, made it possible to formulate the basic rules for the design of geopolymers for the oil industry. An analysis was also carried out on 10 different agents for filtration and 7 moderators to find a working formulation for the temperature range up to 100°C. The samples were systematically examined for changes in composition, strength, and acid resistance was previously measured. Despite the emergence of examples of the use of geopolymers in the construction industry and examples of laboratory testing of geopolymers for the oil industry, to the best of our knowledge, there has been no evidence of pumping geopolymers into a well. Our work is an attempt to develop an adaptation of the construction industry knowledge to the unique high pressure, high temperature conditions of the oil and gas industry. The ambitions of this work go far beyond the laboratory tests and involve yard test experiments.

Depleted Fracture Gradients have been a challenge for the oil and gas industry during drilling and cementing operations for over 30 years. Yet, year after year, problems related to lost circulation, borehole instability (low mud weight due a low fracture gradient), and losses during cementing operations leading to NPT and remedial work continue to rank as some of the top NPT events that companies face. This paper will demonstrate how the geomechanical modeling, well execution and remedial strengthening operations should be implemented to provide for a successful outcome. The use of a Fracture Gradient (FG) framework will be discussed, and the use of a negotiated fracture gradient will highlight how the fracture gradient can be changed during operations. This paper will also show actual examples from Deepwater operations that have successfully executed a detailed borehole strengthening program. Through our offset studies and operational experience, we will provide a format for navigating complex depleted drilling issues and show an example on recovering from low fracture gradients. This paper will demonstrate (1) how our framework facilitated multi-disciplinary collaborative discussion among our subsurface and well engineering communities; (2) how the impacts of drilling fluids and operational procedures can change this lost circulation threshold; and (3) how our negotiated FG approach has successfully delivered wells drilled in narrow margins.

Many mature gas reservoirs in China have very low formation pressure, like Yakela, Dalaoba, Kekeya etc. The formation pressure coefficient ranges from 0.6 to 0.9. Conventional well killing fluids easily leak into the formation and damage the well productivity. There are alternative well killing fluids in the industry to kill low-pressure formations, including foamy fluid, oil-based emulsion fluid and well killing fluid with density reducing agent. However, the densities of these alternative well killing fluids are mostly higher than 0.8 g/cm 3 , and the cost is high if large volume of density reducing agent is used to decrease the density to lower than 0.8 g/cm 3 . In this paper, a formula of nitrogen foamy well killing fluid is developed and successfully used in sand removal operations in low-pressure gas reservoirs. A series of tests are conducted to select the optimal foaming agent, foam stabilizer and other additives. Sodium dodecyl sulfate is selected as the foaming agent. However, the properties of Sodium dodecyl sulfate are not stable in hard water, so we use dodecyl dimethyl betaine with sodium dodecyl sulfate together to increase the foaming ability in tough water environment like in the desert area. Xanthan gum is selected as a foam stabilizer because it can thicken the fluid phase and reduce the drainage speed. Gelatin is also added into the formula because it can form stable coacervate with xanthan gum. The concentration of each additive is also optimized through lots of tests. Then the properties of the foamy well killing fluid are tested. Its density is between 0.50-0.80 g/cm 3 and is adjustable. Under the temperature of 150°C, its plastic viscosity is 51mPa.s; its yield point is 51.5 Pa; the half-life period reaches 3055min. These basic properties meet the requirements of being used as well killing fluid. Salinity tolerance and oil resistance tests are also conducted to see the toughest environment that the fluid can be used in. The results show that the formula can be used in the oilfield where the water salinity is less than 100000 mg/L and the oil content is less than 15%. A model of calculating the equivalent density of the foam is developed. Scenarios of field application and onsite maintenance are also established. If a completion operation or a workover operation lasts for more than 24 hours, the foamy fluid needs to be maintained every day to guarantee its performance in the wellbore. The newly formulated well killing fluid has been used in three wells in Yakela condensate gas filed in Tarim Basin, western China, where the formation pressure coefficient is 0.67 and the formation is strongly water sensitive. A foamy well killing fluid density of 0.72g/cm 3 was used (surface density 0.53 g/cm 3 ) for the sand removal operation in well Ya2-2-4. No fluid loss has been observed during the whole operational process. Neither gas seepage nor oil overflow has been observed during well killing. The well has recovered from production after workover and the production rate reaches 90×10 3 m 3 natural gas with 12t condensate oil every day. The new formula of foamy well killing fluid not only shows good laboratory properties under 150°C, but also proves to be a good solution to the downhole operations in low-pressure and depleted reservoirs.

Sustained casing pressure (SCP) is a very costly event for any operator either at production phase or at the end of a well’s lifecycle. SCP is a result of incomplete hydraulic isolation across hydrocarbon bearing zone. In one of the gas fields in Malaysia, notoriously known for shallow gas hazard, drilled development wells which have reportedly been suffering SCP. In the past, various improvements in cement slurry design and placement methods were deployed in order to provide complete zonal isolation, especially at the shallow gas sand, yet SCP issue was encountered occasionally. In the current development campaign, different strategy to providing annulus sealing was adopted. This paper discusses proactive steps taken in the slurry design, fit together with the dual stage cementing approach, as a primary means of placing cement above the shallow hazard interval. During the design phase, essential key parameters that would lead to successful placement of cement in the annulus as well as unique slurry design that suits for two stage cementing methods were studied. Risk involved in first stage cementing is one of the most important steps that should be analyzed in detail and put mitigation measures in place to ensure the second stage cement job can be performed as planned. In addition to the slurry properties, such as fluid-loss value, gas-tightness, etc., thickening time and top of cement (TOC) of the lead slurry in the first stage cement job has become enormously critical in designing dual stage cementing job in order to assure cement ports in the stage collar are not covered with hard cement forcing the termination of second stage job prematurely. Besides cementing design, careful selection of the stage collar location and casing annulus packer in the string is also of significant importance in leading to successful two stage cement job. Two development wells with above approached has been delivered and no sustained casing pressure has been experienced. This proactive approach to use two stage cementing as primary plan has proven to successfully eliminate the risk of SCP, which was a frequent struggle in their sister wells drilled with primary cementing in the past in the same field. The risk analysis combined with careful considerations of critical cementing design parameters and selection of stage tool location have become a novel approach to combat against SCP in this gas field.