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.

In the event of offshore oilfield blow-out, real-time quantification of both spilled volume, recovered oil and environmental damage is essential. It is due to costly recovery and restoration process. In order to develop a robust and accurate quantification, we need to consider numerous parameters, which are sometimes tricky to be identified and captured. In this work, we present a new modeling technique under uncertainty, which accommodates numerous parameters and interaction among them. We begin the model by identifying possible parameters that contributes to the process: grouped into (1) subsurface, (2) surface and (3) operations. Subsurface e.g. well and reservoir characteristics. Surface e.g. ocean, wind, soil. (3) Operations e.g. oil spill treatment blow-out rate, oil characteristics, reservoir characteristics, ocean current speed, meteorological aspects, soil properties, and oil-spill treatment (oil booms and skimmers). We assign prior distribution for each parameter based on available data to capture the uncertainties. Before progressing to uncertainty propagation, we construct objective response (amount of recovered oil) through mass conservation equation in data-driven and non-intrusive way, using design of experiment and regression-based method. We propagate uncertainties using Monte Carlo simulation approach, where the result is presented in a distribution form, summarized by P10, P50, and P90 values. This work shows how to robustly calculate the amount of recovered oil under uncertainty in the event of offshore blow out. There are several notable challenges within the approach: 1) determining the uncertainty range in blow-out rate in case of rupture occurs in the well, 2) obtaining data for wind and ocean current speed since there is an interplay between local and global climate, and 3) accuracy of capturing the shoreline geometry. Despite the challenges, the results are in-line with the physics and several recorded blow-out cases. Through sensitivity analysis with Sobol decomposition, we can define the heavy hitters. These heavy hitters give us knowledge on which parameters should be aware of. In real-time quantification, this analysis can provide an insight on what treatment method should be performed to efficiently recover the spill. We also highlight about the sufficiency of the model to obtain several parameters’ range, for example blow-out rate. The model should at least capture the physics in high details and incorporate multiple scenarios. In the case of blow-out rate, we extensively model the well completion and consider leaking due to unprecedented fractures or crater formation around the wellbore. We introduce a new framework of modeling to perform real-time quantification of offshore oil spills. This framework allows inferring the causality of the process and illustrating the risk level.

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.

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.

A large gas field with carbonate formations was discovered about 200 km (kilometers) offshore, in water depths of 108 m (meters) below mean sea level. Flow analysis and reservoir depletion studies by the Operator show 7" tubing is required to provide high production rates of about 80 to 120 million Standard Cubic Feet per day (mmscfd) per well as the optimum production and depletion strategy for the field. The field presents significant challenges to well construction and completion. These challenges were considered in the design stage to optimise well completion design and operations. This paper describes the approach and methods used to overcome the challenges in the design and execution stage to optimise the completion design and to manage challenges during construction of the well including: – Due to loss of circulation in the fractured gas carbonate reservoirs, the well will be drilled with Pressurised Mud Cap Drilling (PMCD), a form of Managed Pressure Drilling (MPD). Thus, the design needs to provide for installing the well completion in this condition – The wells required heavy mud weight for drilling and thus, heavy brine weights for well completion. Challenges to avoid or minimise the loss of high cost heavy brine were considered – High reservoir temperatures of about 325 deg. F (degrees Fahrenheit) which lead to challenges of ensuring equipment will continue to work in high temperature environments, high loads / stresses on completion & casing during production, and Wellhead & Christmas Tree & Flowline movement / growth. – Presence of sour gas and CO2 (Carbon Dioxide) which require optimising metallurgy of tubulars and downhole equipment, considering corrosion and cost requirements – Understanding loads / stresses on the tubing and casings with high flowrates and high flowing temperatures – Concerns with formation collapse during production – Corrosion studies to optimise material selection and ensuring well integrity for at least twenty (20) years’ field life – Manage hydrates and scaling while carrying out well completion, well clean and well test operations and during the field life – Acceptable seals, barriers and completion equipment to manage high pressure gas – Wellhead and Christmas Tree that can take the high temperature and sour gas content – Well clean-up and testing after completion in conjunction with drilling operations – Cost and time optimisation to maximize returns on investment for the project. Well completion engineering studies were carried out for each challenge or consideration. Experiences and lessons from similar gas fields were also considered. Corrosion laboratory analysis was carried out to optimise the corrosion resistant alloy for the completion tubular and completion equipment. For each solution to the challenge, cost and time considerations were reviewed and studied to optimise the design, cost, integrity and safety of the wells and operations. This paper describes the approaches and methods taken by the Operator to optimise the Big Bore Gas Well Completion Design including some lessons for improvement after successfully drilling, completing, clean-up and testing of the first well with this completion design.

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.

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.

Typically, most of the well abandonment practice is reference to the recognized industry standards i.e. NORSOK, UK Oil & Gas and etc, and this is how the wells abandonment was carried out in the past. These practices however evolved/changed over time with lessons learnt and experiences and turn into a fit for purpose solutions for the Client. The shift in international and local standards and regulations for a robust plug and abandonment approach has placed the need for a better and long lasting permanent P&A methodology. Adhering to the existing industry standards in well abandonment is somehow not practical and not cost effective to be implemented in different part of the well, where there are major differences in local regulations, reservoir conditions, caprock thickness, well design philosophy and etc. The magnitude of abandonment cost increase is not at par with the risk reduction in long term hydrocarbon leakage. A fit for purpose solutions is recommended in closing the gap between cost and risk. Due to the extremely varied well architecture between wells, the approach to permanent abandonment varies depending on casing sizes, presence of packers and no of casings present to the caprock area. On top of that, identifying the highest depth for a placement of cement plug will reduce on the amount of plugs to be placed, saving rig time and operational time. So far, 16 idle wells have since been permanently abandoned with the systematic approach of applying caprock restoration concept and reinstating the poor isolation across caprock areas with cement with the assistance of technology to the likes of perf-wash-cement, and hydro mechanical casing cutter. These wells have successfully been abandoned as per host authority standards. This paper will explore a major local oil company’ approach to decommissioning of wells, in line with local regulations enforced, while ensuring a cost effective approach is applied in line with the available technologies.

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.

This case study describes the approach taken when drilling an 11 5/8-in. hole section through a salt formation on the Chinarevskoye field in the West Kazakhstan Oblast region where high-intensity brine influxes and subsequent flow had been encountered. The intensity of the brine flow, when encountered, had ranged from 5,000 to 6,000 L/min at an equivalent kick density of 2.2 SG, and it is believed to be among the most intense brine flow experienced in the world during drilling operations. Standard well control measures proved to be inefficient because of the narrow margin between pore pressure and fracture pressure gradients. Several techniques were applied to combat such influxes in a safe manner with minimum associated nonproductive time (NPT). The high-pressured formation in this hole section is associated not only with brine influxes, but also with losses and gas increase scenarios. As a result, the company adopted unconventional drilling techniques with a combination of planned flow-while-drilling (FWD) and mud-cap drilling techniques to reach total depth (TD). These two techniques created a viable and cost-effective solution to mitigate such challenges, helped the company to drill to the planned section TD, and consequently complete the well within the defined authorization for expenditure (AFE) without associated NPT. The paper will cover and emphasize techniques, along with details on running casing and cementing the hole section, which required an unconventional approach for success. The paper will also briefly outline the equipment used, such as rotating control devices (RCDs), a choke manifold, and a separator when drilling this section and their limitations. Despite the complications, the well was successfully drilled, and this experience provided an opportunity for learning. The marked improvements in well control, loss management, and cementation displayed that combining knowledge and experience can reduce the negative impact on well costs when drilling similar cases.

Subsea blowout preventer (SBOP) reliability is a major challenge in Deepwater Drilling & Completion operations, accounting for one of the major equipment failures and Non-Productive Time (NPT) costs yearly. This paper focuses on SBOP technological advancement since the Deepwater Horizon/Macondo incident in 2010, with additional emphasis on reliability, equipment condition monitoring and statistical root cause analysis. After finishing a deepwater well, the SBOP must undergo maintenance, repair if needed and pressure testing before being deployed on the next well. The rig owner is under great pressure to complete this turn-around to avoid waiting time. On an average, in-between wells, rig contractor took approximately 2.6 days extra time (NPT) waiting after completing top hole to get ready to deploy SBOP during 2019-20 exploration and appraisal campaigns. This can be critical during development campaigns where number of rig moves are involved quickly or in cases where top holes are batch drilled the waiting time for SBOP readiness can be as high as 7-8 days per well. Some operators are collaborating with drilling contractors in number of ways to arrange for a second fully assembled and (offline) pressure tested SBOP to be available on the rig (Dual SBOP); deployment of additional trained subsea engineers for performing maintenance/repair. SBOP pressure-testing time can also be drastically reduced by using comparative pressure-testing software to eliminate human error and accelerate pressure testing. Furthermore, leak detection time can be eliminated by installing sensors, and real-time test monitoring providing increased reliability with the additional advantages that conditional monitoring can be enhanced with the same digital sensors. SBOP dashboard that simplifies existing diagnosis and allow remote monitoring of the subsea SBOP control system will improve communication of SBOP health also serve common platform across rig fleets that allow standardization of SBOP diagnostic data and aids in operational decision making Ensuring additional SBOP redundancy especially while operating Emergency Disconnect System (EDS) available through Remotely Operated Vehicle (ROV) control panel or acoustic system. In addition, it is mandatory for the SBOP to have Autoshear and Deadman systems to be able to shut in the well in case of an emergency. Furthermore, technological workshop with several major service vendors have being held to ascertain current advances like Multifunctional profile, Accumulator recharged by ROV, ROV DP system, An Auxiliary Accumulator System and upgraded Acoustic System. In the end, the development of new technologies applied for the SBOP targets the overall cost optimization of the well lifecycle but also assure SBOP functionality. This paper is intended to provide considerations for operators in developing their future campaigns to frame scope of work for SBOP and rig contracting strategy.

As oil and gas reserves mature the world over, operators are looking towards advanced methods of increasing the ultimate recovery from their ageing fields. An energy deficient country of Pakistan relies heavily on oil and gas imports. The country was once self sustaining in at least natural gas needs. A major portion of this gas was produced from the Field-X which was discovered in the 1950’s. The primary reservoir in Field-X is the YZ-Limestone reservoir which bears sour gas. Due to extensive production from the YZ-Limestone formation, the reservoir pressure has depleted to a mere 2.0 PPG in equivalent mud weight, and it being a naturally fractured limestone formation presents numerous drilling challenges. The operator has evaluated a potential higher pressured formation in the deeper horizons of sui field but that requires drilling through approximately 650-690 meters of the YZ-Limestone formation. This feat when attempted conventionally is plagued with numerous problems like, total lost circulation, differential sticking, influxes due to the loss of a sufficient hydrostatic head, and stuck pipe following well control events. To mitigate these challenges the operator, need an effective method to drill through this depleted formation without pumping heavy LCM pills, and multiple cement plugs across the massive cavernous thief zones in the YZ-Limestone formation which could have been detrimental to the production of nearby wells. Moreover, such remedies with specialized LCM’s and acid soluble plugs would have resulted in excessive material cost and non-productive time, which in some instances extended to a period of more than a month. To address the aforementioned challenges in drilling the YZ-Limestone formation, a multiphase managed pressure drilling system was suggested to drill the formation with minimal non-productive time and cost. Multiphase hydraulics were performed to assess appropriate pumping parameters for a near-balanced condition across the YZ-Limestone formation. A closed loop MPD equipment system was designed to help maintain near-balanced conditions in pumping and static (non-circulating) periods. The designed equipment system would also ensure that the risk of H 2 S exposure to the atmosphere was eliminated. The application of a closed loop nitrified mpd system on a recently drilled well proved to be highly successful and reduced the drilling time to just 28 hours by not only eliminating fluid lost circulation but by also delivering an extremely high rate of penetration of 39.2 m/hr. The successful and exemplary application of nitrified MPD has opened up a new horizon for the development of deeper prospects in the Field-X and similar neighboring fields. The paper outlines the design and execution of the closed loop nitrified MPD system.

Losses, wellbore instability, and influxes during drillings operations in unconventional fields result from continuous reactivity to the drilling fluid causing instability in the microfractured limestone of the Quintuco Formation in Argentina. This volatile situation becomes more critical when drilling operations are navigating horizontally through the Vaca Muerta Formation, a bituminous marlstone with a higher density than the Quintuco Formation. Controlling drilling fluids invasion between the communicating microfractures and connecting pores helps to minimize seepage losses, total losses, wellbore fluid influxes, and instabilities, reducing the non-productive time (NPT) caused by these problems during drilling operations. The use of conventional sealants – like calcium carbonate, graphite, asphalt, and other bridging materials – does not guarantee problem-free drilling operations. Also, lost circulation material (LCM) is restricted because the MWD-LWD tools clearances are very narrow in these slim holes. The challenge is to generate a strong and resistant seal separating the drilling fluid and the formation. Using an ultra-low-invasion technology will increase the operative fracture gradient window, avoid fluid invasion to the formation, minimize losses, and stop the cycle of fluid invasion and instability, allowing operations to maintain the designed drilling parameters and objectives safely. The ultra-low-invasion wellbore shielding technology has been applied in various fields, resulting in significantly improved drilling efficiencies compared to offset wells. The operator has benefited from the minimization of drilling fluids costs and optimization in drilling operations, including reducing the volume of oil-based drilling fluids used per well, fewer casing sections, and fewer requirements for cementing intervals to solve lost circulation problems. This paper will discuss the design of the ultra-low-invasion technology in an oil-based drilling fluid, the strategy for determining the technical limits for application, the evaluation of the operative window with an increase in the fracture gradient, the optimized drilling performance, and reduction in costs, including the elimination of NPT caused by wellbore instability.

Extended reach well (ERW) can be extremely drilled to distant reservoirs to reduce the infrastructure and operational footprint. Drilling ERW and extending their reach to greater depths requires both improved equivalent circulating density (ECD) and frictional resistance due to large horizontal displacement, long open hole and borehole unstability. ECD is one of the keys to safe and efficient drilling, especially in complex formations with narrow pressure profile, and wellbore frictional resistance appreciably influences drilling torque and drag, as well as casing running. This paper presents several methods, including continuous circulating valve(CCV) drilling technology, cuttings bed removal technology and chemical friction reduction technology, to promote the success of ERW drilling. The applications are realized by means of adding CCV, cuttings bed cleaner to the drill string and chemical friction reducer into the drilling fluid. Respectively the CCV drilling technology realizes the continuous circulation of drilling flooding, and cuttings bed removal technique utilize integrated design of hydraulic machinery with hydraulic parameter adjustment and flow passage design, to enhance turbulence velocity and strength of drilling fluid flow field, which both can effectively improve the efficiency of carrying bit cuttings, and reduce the fluctuation of ECD. Chemical friction reduction technology is mainly composed of chemical frictional drag reduction agent which belongs to organic anion compound products, and has excellent super anti-wear lubrication. Results show that the fluctuation of ECD in the high-risk well section with well loss was controlled within 2.5%, and narrow density window formation (0.18g/cm3) was drilled safely without any caving and leakage. The friction coefficient ranged from 0.4 to 0.25, with 40% decrease compared with previous wells in Huizhou Oilfield. And also the ROP increased by 45% due to effective transmission of WOB. The technologies shown in this paper comprise key innovative technologies in ERW operation in Nanhai East. Less time is occupied in equipment installation, as well as simple operation flow, however with improved stability and remarkable performance. It lays a foundation for further study of ultra extended reach wells with greater difficulty and challenge.

The southern part of Pakistan is known for its rich hydrocarbon potential. Most fields in the locality have matured, and pressure depletion has created problems in further field development. Located in northern Sindh, Qadirpur is one such field, which once accounted for 20 percent of Pakistan's total gas production. The highly fractured Sui Main Limestone (SML) formation is the primary reservoir in Qadirpur field, which has depleted over the years. Recent attempts to drill and produce from the SML formation were plagued with numerous problems including total circulation losses, extreme formation invasion damage, stuck pipe, and well-control events. Severe circulation losses not only led to excessive drilling time, but the heavy lost circulation material pumped into the wellbore invaded the formation and completely choked it off. The operator made multiple attempts to clean off the wellbore and kick off the well, but eventually no production was observed, ultimately leading to plugging and abandonment. The operator thus sought a solution that would enable drilling through the SML formation with maximum efficiency while minimizing formation damage during the drilling process. The operator desired to keep the SML formation in a "virgin" state from the beginning of drilling to the final production stage. The SML formation currently exhibits a low depleted pressure of about 3.9 ppg equivalent mud weight (EMW) and drilling through it requires a very low bottom hole pressure to mitigate circulation losses and subsequent invasion damage. Underbalanced drilling was thus considered for drilling through the SML formation in a proposed well, but a multitude of issues had to be addressed for successful execution of an underbalanced program. Some of the challenges in designing an underbalanced program on the subject well included maintaining underbalanced bottom hole pressures in the presence of high annular pressure losses, selection of appropriate directional drilling equipment for use with a lightweight multiphase fluid, maintaining efficient hole cleaning in the horizontal leg, designing an appropriate technique for tripping in and out of a live well, and finally achieving greater drilling performance to offset the cost incurred in underbalanced drilling. A nitrified foam system was selected to achieve an equivalent circulating density below 3.9 ppg. A special formulation of polymers was used in the base fluid for foaming to achieve enhanced cuttings carrying and suspension capacity. The directional drilling equipment was also customized to be used with a multiphase fluid medium. Lastly, a downhole isolation valve was deployed in the casing string to allow tripping of the drill string in a live well. By the application of underbalanced nitrified foam drilling, the operator was able to cut down drilling time by half and keeping the SML formation in a "virgin" state at all stages delivered an unprecedented production rate from the subject well.

In this study, the highly sensing chemo-thermo-piezoresistive smart cement behavior as a function of temperature and pressure with a water-to-cement ratio of 0.38 was investigated. Series of quality control, curing, compression and high-pressure high-temperature (HPHT) lab experiments were performed to evaluate the smart cement behavior with pressure and temperature variations. Vipulanandan p-q curing model was used to predict the changes in resistivity with curing time. The piezoresistivity strain of smart cement after 1 day of curing under 140 °F was 207% which is much higher than the regular cement failure strain of 0.2%. The Vipulanandan p-q piezoresistivity model also predicted the experimental results successfully. Observed fluid loss and gas leak after 30 minutes of testing was recorded. The measured fluid loss was predicted using the Vipulanandan fluid loss model and compared to the API static fluid loss model. Smart cement detected and sensed gas leak throughout the fluid loss test. During the gas leak through the piezoresistive smart cement slurry, the resistivity change was positive which could be used as an indicator for immediate gas migration. During the gas leak in the smart cement slurry, the resistivity increase was about 36% at pressure gradient of 1,800 psi/ft for 70 °F curing. Vipulanandan fluid flow model, generalized Darcy's Law, predicted the non-linear responses of gas leak velocity (discharge per unit area) to the applied pressure gradient. Additionally, the electrical resistivity changes predicted the gas leak velocity in the smart cement at different curing temperatures.

Drilling companies are constantly evaluating ways to improve the efficiency and safety of their operations, the way the returns of the well are circulated while drilling has remained unchanged for decades, however, having a circulating system open to the atmosphere imposes a risk to the drilling crew in the rig flow. Conventional influx detection methods can easily allow the gasification of the mud column in the annulus before it is noticeable and H2S or flammable gas alarm can be triggered before any action is taken. A rotating control device (RCD) is a piece of equipment that diverts the returns of the well from the rig floor while allowing the drill pipe to be rotated and reciprocated, that means tripping and drilling operations can be performed while the well is isolated from the rig floor by the RCD. The RCD is a key component in Managed Pressure Drilling (MPD) operations as it is responsible for containing the annular surface pressure and preserving the integrity of the circulation system, hence maintaining a slight overbalance condition on the well, additionally the RCD can be deployed independently for other applications that enhance the safety and optimize the costs of the drilling operation. For this reason, efforts are made to ensure that optimum operating conditions are present to reduce the chances of system failure. Historical data detailing the performance of RCD systems, including total stripped footage, total rotating hours and failure mechanisms were used to evaluate the reliability of this technology and to set operating limits to optimize its performance. Historically there are conditions that are known to reduce the life span of RCD bearing assemblies, such as misalignment of the Blowout Preventer (BOP) stack, hard banding or bad condition of drill pipe tool joints, excessive drill pipe vibration, temperature and type of fluid out of the well, among others. Ensuring that the operating limits are observed regarding rotating speed, pressure and temperature were observed to be key to maximizing the life cycle. It was observed that the base technology over which RCDs are designed is far from recent and new additions to the current setup are needed to "smarten up" an otherwise very basic piece of equipment, this with the intention of obtain better data regarding its operating conditions and the parameters that affect its performance. New technologies in terms of elastomer compounds, seal design improvements, monitoring systems and implementation of artificial intelligence are some of the upcoming developments discussed in this document and that are to be implemented in the short and medium term in RCD operations in Kingdom of Saudi Arabia.