This paper presents a two-parameter approach, using only density and Marsh funnel time for providing a complete rheological analysis of fluids, encompassing all six standard dial readings as established in the American Petroleum Institute (API) Recommended Practice 13D. The scope of the study includes experimental, analytical, numerical and statistical analyses of flow in the Marsh funnel. A mathematical analysis is developed based on the Marsh funnel’s geometry and a wide suite of machine learning algorithms are applied to model and predict rheological profiles across the funnel. commercially available numerical simulation software is applied to build a model using computational fluid dynamics. Results from the numerical analysis are corroborated by analytical calculations that are then used to develop a statistical framework for predicting dial readings under various shear rates (3-600 RPM). Experimental results from more than 1500 mud tests are utilized to build ten machine learning algorithms modelling the rheological properties of the fluids. Their performances are evaluated to determine the best models based on three metrics: R-squared values, root mean square error and mean absolute error. Predictions are performed on new mud data and comparisons are made among the ten predictive models broadly categorized into generalized regression models, decision tree-based techniques and miscellaneous approaches. The models show high predictive accuracies on new drilling fluid samples with the performances generally improving with increasing shear rates. A mathematical analysis of the geometry of the Marsh funnel has been utilized to establish a methodology to quickly and accurately perform rheological studies on fluids. Results from experimental, analytical, numerical and statistical studies all closely agree with each other. The outcome of this study can readily be employed at the wellsite to obtain much value from the routine hourly Marsh funnel readings. This can serve as a quick substitute to infrequent conventional rheometer outputs, which are typically obtained only one to four times per day at the field. The rheological results and other derivates such as plastic viscosity (PV) and yield point (YP) are immediately produced after each Marsh funnel test. Informed decisions such as updating hydraulics modelling to improve ROP and hole cleaning can be thus be achieved. This work engages the disciplines of rheology and machine learning to produce a result that enhances the workflow during drilling operations. Added value is derived from an already existing tool to better monitor fluid properties frequently, which is beneficial to the overall surveillance of the drilling fluid system.

Matrix acidizing is one of the most common well stimulation methods in Malaysian brown fields. Formation damage caused by fines migration has been reported to be among the main reason for productivity decline. The need to conduct acid stimulation arises when the initial rates of the wells are below expectation or when the productivity of the reservoir drops significantly. Various mud acid formulations have been used to treat the wells from the past until recent years. However, some well treatments resulted in low success rate especially for reservoirs with vast variation and complex formation mineralogy. This highlights the need for modified acid recipe from the conventional mud acid system. Mud acid systems are often highly corrosive, resulted in unwanted secondary precipitation and require multiple additives during the treatment. This paper highlights the evaluation and comparison of the novel Modified HF acid against conventional mud acid system through core flooding tests. Multiple cores with various mineralogy were tested. The laboratory test showed that the Modified HF acid system able to generate better permeability improvement compared to mud acid systems. The modified acid recipe gradually sequestrates the major iron minerals throughout the injection to avoid unwanted secondary or tertiary precipitation that could damage the formation. Subsequently, the chemical was successfully piloted in two fields and replicated in other fields across Malaysia. The field applications proved that the novel Modified HF acid system generated outstanding results in production gain and improved the total economics of the project. The novel acid recipe can be an alternative solution when simpler acid systems are favored with lower treatment cost. This chemical is also beneficial for wells that located in small platforms or jackets where minimal amount footprint is available during job execution.

An active filter cake technology (AFT) was chosen to improve production performance in the tight reservoir following a comprehensive laboratory study to determine formation damage impact caused by previous non-damaging fluids (NDF). The AFT was successfully field trialed on two wells with production improvement vs. acid stimulated offset wells. This paper discusses laboratory data and improved field productivity. It documents reduction of torque/drag with increased rate of penetration without using a lubricant during drilling. Comprehensive laboratory testing to identify origins of deficient production was completed by thoroughly reviewing drilling and completion practices, and completion type implemented. Compatibility of base brine with formation water; formation damage impact of drilling fluids used in reservoir and effectiveness of hydrochloric acid (HCl) solution pumped through coiled tubing to destroy the filter cake constituted the first phase of the investigation. Assessment of several fluids capable of mitigating concerns was performed in the second phase. The optimization and customization of candidate fluids to address all challenges was the third phase. Last phase consisted of field trials and assessment of production results. Testing identified a potential incompatibility of calcium chloride brine and the formation water. The brine was replaced with monovalent halides brine. The previous NDF system exhibited elevated filtrate volume and a high concentration of acid insoluble materials which together significantly impacted productivity. Review of the completion operation and laboratory results proved filter cakes of reservoir drill-in fluids (RDF) cannot be homogenously and entirely removed with HCl solution using coiled tubing. Only less than 50% of the wellbore length can be accessed with coiled tubing and treated with acid. The acid treatment dissolved less than 10% of filter cake when sumulated field conditions in the laboratory. Likewise, the filter cake breaker cannot be implemented on barefoot completion as its volume is totally lost to the formation after breakthrough before complete filter cake dissolution occurs. The study recommended AFT with 100% organophilic bridging materials. The AFT was successfully field trialled in two wells. Post analysis of drilling parameters with AFT exhibits lower torques without addition of lubricant compared to previous fluid along with 186% increase in average rate of penetration which saved 79 hours of ILT/well. Production kicked-off without assistance from lighter fluid (N 2 gas) or stimulation showing promising results compared with near-by wells. The 100% organophilic bridging materials were used for first time in field. It proved acid stimulation can be eliminated for the tight reservoir while improving the oil production rate compared to the offset wells. In addition to inherent productivity improvement characteristics, AFT is appropriate where cheesing and greasing of RDF are common problems with lubricants. AFT demonstrates reduced torque without lubricant addition in extended horizontal deviated wells and excellent production while eliminating post stimulation.

This paper presents recent experience with a new 4 ¾-in logging-while-drilling (LWD) nuclear magnetic resonance (NMR) tool. Data from several wells drilled provided real-time operational insights and new petrophysical learnings. The new LWD technology presents a novel capability to measure NMR T 1 and T 2 distributions simultaneously with reduced sensitivity to drilling mud conductivity. Additionally, a real-time sensor motion-warning system is implemented to check if the drilling environment is suitable for NMR data acquisition. The real-time T 1 and T 2 spectra, communicated by mud pulse telemetry, compare favorably with the full dataset retrieved from the tool memory. For detailed back-to-back comparison, the LWD NMR measurements were followed by wireline (WL) NMR logging in three wells. In carbonate reservoirs, the main objective is the evaluation of the new tool's capability to resolve carbonate pore size with slow NMR relaxation rates. Another set of NMR logs included time-lapse repeat passes in a well drilled with oil-based mud (OBM) across a clastic reservoir. With the NMR property contrast between formation oil, water, and oil-based mud filtrate (OBMF), this sequence of measurements resolved rock types and provided unique insight to the process of mud filtrate invasion. In a carbonate reservoir, the LWD NMR data were processed to estimate micro-, meso-, and macropore volumes. The real-time partial porosity estimates are in excellent agreement with the core-calibrated wireline evaluation. Another carbonate formation contains high permeability layers embedded in a microporous rock. This layering is resolvable by NMR logs only. The real-time LWD NMR logs successfully located the high-quality zones as verified later by wireline logging. In the clastic reservoir, the LWD NMR data acquired while drilling indicated native light hydrocarbons, whereas the subsequent LWD reaming and wireline NMR passes showed a displacement of native hydrocarbons by OBMF. This fluid displacement appears as a shift of the free fluid signal from several seconds in the LWD log to about 600 ms in the WL NMR T 2 spectrum. The native hydrocarbon signature observed by LWD NMR is in good agreement with the mud gas log. OBMF invasion occurs shortly after drilling as indicated by the differences observed in the LWD NMR relog data acquired several hours after the while-drilling pass. The wireline NMR data, logged about four days after drilling, shows advanced stages of OBMF invasion, including formation water displacement and wettability changes in intermediate and large pores. Finally, the environmental noise remains low in an LWD NMR dataset acquired in a well where the mud salinity changed by several folds, indicating that mud salinity has little effect on the quality of LWD NMR logs in slim holes. The new slim LWD NMR technology has demonstrated its robust capability to provide T 1 and T 2 logs by several examples. For the first time, a time-lapse comparison of NMR logs showed that OBM filtrate invasion could happen in silty sands with high capillary-bound fluid fractions.

An article presents comparative results of pilot of an innovative blocking pack for well-killing operation – emulsion-suspension system with supercharged nanoparticles (ESS). The ESS is characterized by the following competitive advantages: unlimited compatibility with petroleum reservoir fluids, gases, rocks and well-killing brine, adaptability of specific gravity in a wide range (900-1400 kg/m 3 ), foreseeable rheology, alteration of wettability of rock surface, reversibility of blockage, no harm to downhole equipment, system of oil and gas gathering and environment. The ESS blocking pack pilot was carried out in multifractured horizontal wells under high-pressure (39.5 MPa) and high temperature reservoir conditions (115 °C) of Tortasinskoe oil-gas field, Western Siberia, Russia. The reservoir rock of Tortasinskoe oil-gas field is sandstone, characterized by low permeability (0.001-0.0001 μm 2 ) and porosity (13%). A comprehensive laboratory tests program was executed for ensuring successfulness of the ESS blocking pack pilot in the complicated reservoir conditions of Tortasinskoe oil-gas field. The laboratory tests program included a basic research and specific experiments. The results of pilot confirmed significant competitive advantages of the ESS blocking pack in comparison with a synthetic polymer blocking pack, which was unsuccessfully applied earlier on the same production well. The ESS blocking pack showed high performance for well-killing operation in complicated HPHT reservoir conditions than widely used worldwide synthetic polymer system did not work at all.

Frequent drilling challenges for high-inclination well paths in the overburden Laffan and Nahr-Umr shales involve stuck pipe incidents and caving, leading to sidetracking in extreme cases. Advanced geomechanics studies including both an anisotropic wellbore stability model and shale stability analysis were conducted on acquired cores to better understand these problematic intervals for improving drilling efficiency and reducing costs by mitigating wellbore instability. The study analyzed the preferential directions of deformation and failure (i.e., anisotropic) in the shales and their time-dependent behavior in reacting with drilling fluid. Shale samples were preserved to avoid changes in mechanical properties due to the high clay content and low permeability. Two overburden shale intervals were analyzed to determine strength and elastic anisotropy. Dynamic anisotropic elastic properties were obtained via ultrasonic wave propagation. Strength anisotropy was evaluated using the plane of weakness model that assumes a heterogeneous media composed of a matrix rock and plane of weakness (e.g., bedding/laminations, interface between lithotypes or laminations). The test results showed a drop of compressive strength from 50% to 70% for samples with inclination from 38 to 62 degrees, which increases the chance of formation collapse of the laminated shales at such wellbore deviation. The anisotropic analysis proved that the stress field is higher when anisotropic properties are considered, which leads to higher propensity for failure. Shale stability tests demonstrated that most of the instabilities identified in the Laffan and Nahr-Umr formations were mechanical in nature. The optimal mud weight is strongly dependent on the well trajectory to account for the plane of weakness and strength anisotropy. Combing data from laboratory tests with advanced sonic logs enabled a more robust evaluation of the formation anisotropy at the well scale, which improved both stress predictions and mud-weight window predictions along the well trajectory. This anisotropic well-centric model helped for determining more appropriate mud weights and salinities for upcoming directional wells. By obtaining core samples in the shale formations, the operator was able to test and characterize the anisotropic behavior and also analyzed the time-dependent behavior. These results were combined with advanced sonic logs to better understand and mitigate wellbore instability induced from the plane of weakness.

Hydraulic fracturing technology has grown popular with the rapidly increasing development of tight conventional and unconventional reservoirs. A major concern with this technique is the use of large amounts of water in these treatments. The use of water causes many potential damaging issues in the formation and limits the amount that can be saved for future generations. One solution is waterless fracturing treatments, which were developed to reduce or eliminate the need for water in hydraulic fracturing. Hydraulic fracturing treatments consume at least 200,000 gallons of water in conventional wells and up to 16,000,000 gallons of water in unconventional wells. The pumped water must include clay stabilizers to deal with the sensitive clays in the formation. Additionally, using water poses a risk of inorganic scale precipitation near the wellbore. Water can also cause severe emulsions that can lead to emulsion blockage cases. Moreover, there are significant reports of water blockage cases in tight gas wells. Only a mere 10-30% of pumped water flows back after the treatment, with the rest attached to clays, or stuck in the pores due to high capillary pressures. Water-based fluids can also cause alterations to relative permeability, and liquid holdup cases in many gas wells. These issues can certainly increase near wellbore skin and reduce production rates. At the end of the treatment, water still causes issues related to disposal and separation prior to diverting it to the plant. The main challenges in developing waterless fluids include feasibility, environmental friendliness, and effectiveness to stimulate the reservoir. This review will cover the various waterless fracturing methods such as hydrocarbon-based, liquid CO 2 , energized, and foamed fluids (CO 2 and N 2 foams) as well as their advantages and disadvantages. Studies into the properties of these fluids, such as rheology, solubility, compatibility, will also be discussed. Field trials will be examined where applicable. This literature review examines various waterless alternatives to traditional fluids for hydraulic fracturing. From this paper, readers can better understand the nature of waterless technologies and be able to better evaluate these technologies for fracturing purposes.

Unmanageable losses through carbonate formations led to pumping water through the drill pipe and heavy mud cap in the annulus to drill with total losses. Although this technique overcomes the need to fly mix drilling fluid, it adds the complication of pumping heavier mud cap into the annulus. Pressurized Mud Cap Drilling (PMCD) was introduced the first time in the project to eliminate the requirement of mud cap for improve wellbore condition, efficient well control and to optimize the overall cost while drilling with total losses. As mud cap density increases based on reservoir pressure, so does solids concentration in mud cap. Apart from mud cap getting extremely expensive at higher densities, it deteriorates hole condition due to continuous addition of solids especially for horizontal wells where solids keep piling up on the low side of the wellbore. With total losses in the reservoir, drilling is followed by image log, followed by reaming run and finally open hole completion runs to isolate those fractures. On wells where higher density mud cap was used, severe hole problems leading to stuck pipe were faced either during logging or open completion runs. On most of the occasions, solids of mud cap have been proven as the root cause for worsening the situation. PMCD has been introduced as a solution to such high-pressure wells to drill and complete them with total losses more efficiently and cost-effectively. It not only reduces the volume of solids dumped in the wellbore in the form of mud cap thus improving the hole condition but also saves the immense cost of mud cap which is especially massive for long laterals while dealing with long reaming operations. The above motivation of finding a solution for drilling in total loss environment emerged from one of the wells where pipe conveyed logging string (TLC) got differentially stuck while pumping a 90 pcf mud cap. The pipe could not be recovered even after cutting it inside the casing shoe confirming it was packed off with solids laden mud cap. The well was sidetracked and was completed with PMCD successfully without any complications. After that job, PMCD has been implemented in five other land wells successfully and being recognized as standard practice for drilling high-pressure wells with total losses. This paper illustrates the challenges faced by turn key project team due to total losses and drilling with mud cap, and overview of PMCD procedures, comparison of mud cap and the inherent advantages of PMCD over mud cap drilling. It provides details of the well which could only be recovered using PMCD after sidetrack due to stuck pipe.

This paper presents a comprehensive laboratory and field study discussing development, formulation, and application of a new flat rheology drilling fluid system that meets the challenges faced when drilling in an ultradeepwater well environment. The use of this new flat rheology drilling fluid system for the first time in Asia-Pacific Region has created the potential to efficiently drill more challenging deepwater and ultra deepwater wells in offshore Myanmar, Malaysia, and other associated countries. In a deepwater block situated on Myanmar's west coast, conventional synthetic-based drilling fluids (SBM) have been used to drill all the wells to date. During the planning phase of an ultradeepwater well with a water depth of 2,300 m, it was found that the equivalent circulating density (ECD) with a narrow pore pressure and fracture gradient would have increased downhole complications leading to non-productive time (NPT). The main concern was not being able to reach total depth (TD) or successfully setting casing on bottom with the original well design, requiring implementation of a contingency casing and pushing the operational cost over authority of expenditure (AFE). To overcome the challenges, a new flat rheology drilling fluid system was introduced based on ECD challenges and rheology requirements. The initial study of modelled hydraulics showed a significant ECD reduction using a flat rheology drilling fluid system. The first round of laboratory tests exhibited promising results of flat rheology across all temperature ranges and after iterating numerous formulations developed with local seed mud were narrowed down to two final formulations of 1.08 sg and 1.17 sg. The formulation was field trialed with some slight adjustment in chemical concentrations to meet specific field mud properties. The well was drilled successfully with no major variation in ECD or issues related to the large temperature range. Implementing this customized solution combined with precise strategy led to successful results in efficiently completing one of the most challenging wells of the campaign. The paper presents a comprehensive study of the challenges formulating and implementing a new flat rheology drilling fluid system. Additionally, a detailed study on ECD challenges when drilling an ultradeepwater well is also done. The paper also discusses the comprehensive pit management program and required treatment plan for drilling. Finally, the paper aims to compare the existing results with previous drilling techniques, which will assist operators with the future advances in similar fields.

Drilling wells in some locations in the Greater Burgan field in Kuwait, can demonstrate significant challenges across the intermediate section. Part of these challenges are combining the carbonate formations with the weak unstable Ahmadi shaley formations at the bottom of the section. This makes it challenging to drilling engineers and difficult to balance between natural mud losses across the carbonate formations and weak shale that requires higher mud weight. Adding to these challenges, the limited surface locations in the field, that forces the well design trajectory to be deviated, which makes the mud window even smaller and shifts it higher. Zonal isolation across this interval adds an additional challenge, as it will prevent gas and liquid to escape from high pressure deeper zones to shallow lower pressure zones and probably to surface, which potentially may cause well integrity issues in the future. This paper represents a case of formation collapse on a casing prior to cementing operation, how it was detected, how it was handled and how successfully the well was completed.

Loss circulation is encountered frequently while drilling fractured carbonate reservoirs in specific field. The field practice was attempting to cure losses and if incurable, drill blind to total depth (TD) followed by run and cementing of the liner. The interval from loss zone to liner top was covered by the cement squeezed from liner top. The require time to try to cure the lost circulation zone plus squeezing cement job was approximately 15 days. Several optimization initiatives were implemented to reduce this time to less than seven days. There were at least eight round trips carried out in different ways by different operators to complete the operation of attempting to cure the losses and a liner top squeeze. The engineering team evaluated this for potential optimization, first to identify whether or not losses need to be attempted to be cured to save the time lost on unsuccessful attempts. Second, to analyze the lessons learnt and build on that optimization strategy to reduce the number of trips Lastly to rework the cement slurry design to reduce the number of attempts to squeeze liner top. As such a detailed strategy was formulated regarding when and how to cure losses followed by an optimized procedure for liner top squeeze which saves three round trips. Further, the liner top squeeze operations previously took multiple attempts of squeeze before a successful pressure test was achieved. Based on the lessons learnt, the slurry design was optimized from several aspects including, slurry density, rheology, thickening time and the pumping and displacement procedure was created which helped to reduce the number attempts from six to only one. Another optimization implemented was enabling the loggers perform pressure pass for cement evaluation by the utilization of tractor instead of conventional (Tough Logging Conditions) TLC which not only saved time but also depicted better the condition of cement behind liner. Finally, a robust risk assessment encompassing all possible contingencies for expected issues was incorporated. The optimized liner top squeeze strategy has been implemented at five wells with 100% success, reducing the overall operation time from more than two weeks to less than one week while improving cement quality behind liner to ensure zonal isolation as per requirements. This paper provides details of how the cement slurry, operations sequence and tools selection were enhanced well by well based on continuous improvement. Since cementing liners across loss circulation intervals exists in most of the carbonate reservoirs worldwide, this paper will help to achieve better zonal isolation in losses environment with lower cost and lesser time.

Acquiring reservoir fluid samples through formation testers is critical to asset evaluation in most oil and gas drilling operations. From the time this technology was introduced to the industry, the key challenges have been in planning the job, estimating contamination during operation, and obtaining clean fluid samples in the shortest time possible. The objective of this paper is to create a new data-driven model to proactively simulate the cleaning process in order to provide a practical job-planning tool that optimizes fluid sampling. After detailed analysis of formation pump-out cleaning behavior and oil-well sampling, a parametric study with nearly a hundred thousand scenarios was designed to model fluid behavior during sampling. The simulation scenario is a multi-component model with radial geometry, capable of handling complex reservoir rock, fluid composition, probe geometry, and sampling conditions. Compositional simulation output is then used to generate the comprehensive database of the fluid sampling and cleaning processes. The study is used to determine the sensitive parameters related to sampling and contamination. Full factorial experimental design was used to build nearly one hundred thousand scenarios with more than 10 relevant parameters. Outputs were analyzed through a variety of visualization and statistical techniques to understand cleaning behavior in different initial and operating conditions. One-factorial analysis and statistical tests, including analysis of variance (ANOVA), were used to determine the significance of the different parameters. The most influential parameters have been selected and used as input to the representative model in order to predict pumpout volume and corresponding contamination. In this work, multiple data-driven models such as Neural network, Random Forest, and Gradient Boosting are presented. Furthermore, multiple mathematical equations have been compared to fit the contamination trend, and methods of estimating their best fit parameters are presented. Blind testing has been performed to evaluate performance of the developed models, showing promising results. The workflow, database, and the developed models can be used to perform forward modeling of sampling jobs in different reservoirs, drilling muds, and operating conditions for both wireline and logging while drilling (LWD). This enables an effective and practical job-planning tool implementation, whereby a tool string can be optimized to reduce sampling time while improving the quality. The state-of-the-art workflow deployed in a commercial reservoir simulator combines physics, programming, statistical analysis, and machine learning techniques to tackle the challenging problem of sampling. The workflow and data can be used during operations with various wireline formation testing (WFT) and LWD testing tools to optimize cleanup and sampling of formation fluids. Simulations of different realizations of reservoir properties, drilling mud invasion profiles, and cleanup operations also helped develop a useful and diverse pumpout database.

This well was drilled with the objective to support the pressure sustainability of multiple producer wells across Lukhweir-2 formation based on ERD approach. This paper presents the challenges faced in planning and drilling of subject ERD well with a total measured depth of 27,352ft (8.34km) and having horizontal hole of 11,300ft (3.45 km reservoir contact) with directional difficulty index (DDI) of 7.208 using light/slim casing design. Planning of this well started by meetings and collaboration with asset team to a common objective of delivering the longest well across Lukhweir-2 (LK-2) reservoir to support the multiple producers and mitigate all the associated risk by proper planning and drillability analysis such as trajectory design, collision risks, BHA, hydraulics and casing designing. This paper will explain the novel approach of mitigating the challenges faced while drilling this ERD well such as concerns about surface hole drilling (30 deg across interbedded shale formation), challenge in running 7" long liner (>8000ft across multiple reservoir) and overcoming surface pressure and torque limitations while drilling. Results, Observations, This ERD WAG injector well is the first and longest to be drilled with 6" drainage across Lukhwair-2 reservoir from artificial island to have 11,300ft of 6" Geo-Steered Horizontal hole section using Slim Casing design which gives the total well measured depth of well 27,352ft MD / 10,101ft TVD (2.7 ERD H:V ratio) Results from this well have proven that ERD wells with longer reservoir contact have significantly improved well performance, enhanced reservoir management and reduced field development cost. This paper summarizes the practice and technology used to drill successfully the longest ERD / MRC well using slim design practice which includes the utilization of special dope for 4" DP to increase the torque limit, use of special surface equipment called chillers/coolers to over overcome high downhole temperature. This paper will also capture the drivers, selection criteria and lessons-learned over the entire well drilling. The challenges/mitigation explained in this paper will stretch the ERD/MRC boundaries and support engineers to design the complex 3D wells with slim/light casing design and can achieve extended targets with 100% integrity.

For fields with hard and brittle shale sections that have microfractures (either preexisting in the formation or induced by drilling operations), we experienced troublesome drilling with a relatively low rate of penetration (ROP). A systematic experimental work has been implemented to discover whether nanoparticles added to drilling fluids penetrate shale formations and improve wellbore stability. Starting with quantitative analysis of the shale rocks, we found the mineralogy and clay composition of these rocks by using X-ray diffraction (XRD). The XRD analysis shows that the shale rocks consist of mixed-layer clays and are very heterogeneous. The shale samples were then characterized by X-ray computed tomography (XCT) and scanning electron microscopy (SEM) to gain an understanding of preexisting microfractures. The XCT results show that multiple cracks are irregularly distributed inside the shale with widths between 10 to 25 μm. Smaller cracks with widths ranging from 100 to 250 nm were also observed via imaging on the shale sample surface using SEM. To answer whether adding the nanoparticles improves wellbore stability, we first designed the nanoparticle infiltration test by flowing nanoparticle dispersions through the shale assembly at an inflow pressure of around 800 kPa. After the shale samples were subjected to infiltration tests with durations between 9 to 27 days, the injected depths of nanoparticle along cracks was determined to range from 190 to 420 μm, as seen by optical microscope images. Higher resolution SEM images show that the maximum infiltration depths of the nanoparticles range from 2 to 5 μm in different crack-free locations. Nanoindentation tests were then conducted under the continuous stiffness measurement (CSM) mode to probe the mechanical properties of the pre-treated and post-treated shale samples. At two indentation depths, the averaged Young's modulus E for the shale sample before and after nanoparticle infiltration significantly increased from 29.5 to 34.0 GPa (at a depth of 500 nm) and from 29.0 to 33.3 GPa (at a depth 3000 nm), respectively. The nanoparticle infiltration and nanoindentation test results demonstrate that nanoparticles can filter into and further strengthen the shale formation. We also formulated nanoparticles in our drilling fluid and performed the pressure transmission test (PTT) to see their sealing effect on the field cores. A highly favorable plugging result was obtained from the PTT using base mud with nanoparticles. Therefore, it is concluded that our systematic experimental work has delivered results, which support the practice of using nanoparticles to improve wellbore stability for shale formations.

This paper discusses how an organophilic clay-free invert emulsion reservoir drill-in fluid (OCF-IEF-RDF) was customized to successfully break the longest well record in the Middle East and North Africa region and the 4th longest extended-reach drilling (ERD) well globally. The successful design included extensive lab testing to optimize performance of this innovative low-solids OCF-IEF-RDF used to drill the 25,415 ft. horizontal reservoir section. This specially designed drill-in fluid reduced key risks for drilling ERD-type wells and kept parameters within necessary specifications to set new limits for drilling performance, maximizing horizontal section displacement/reservoir drainage, and production output. Challenges and risks related to drilling extended-reach wells require particular focus on the drilling fluid design in order to meet these challenges and to mitigate the risks. In addition, proper planning beforehand, and close monitoring and control of many fundamentally important parameters when drilling are required in order to execute successfully the drilling and completion phases for such wells. While evaluating the feasibility of drilling this well, establishing appropriate fluid system properties was a key focus area. The rheology profile was optimized for hydraulic management, hole cleaning, and fluid stability, and the ground marble bridging package was designed for minimum damage to the reservoir. Lubricity and rate of penetration (ROP) maximization were addressed by designing a low-solids OCF-IEF-RDF where the base brine was calcium bromide. The paper shall discuss both the processes used during the planning phase, including laboratory testing and hydraulic simulations, and the procedures followed during the execution phase, and how they helped ensure trouble-free performance during drilling. Proper planning and execution, using best-available drilling practices, enabled drilling of this record-breaking well without encountering significant issues that could impact rig time and increase costs. Selection of an OCF-IEF-RDF to provide low Equivalent Circulating Density (ECD) performance in a fragile gel fluid with low sag risk was fundamental to achieving required fluid properties. The low-solids design improved ease of deployment of the weighting material (ground marble) compared to similar fields where more conventional organophilic clay-based fluids are used. More than 25,415 ft. were drilled in 9 days with an average ROP of 216.8 ft. /hr. and 216.6 Rotating Hours and the best 8.5" daily footage of 4,121 ft. in the field. This resulted in the completion of the drilling operations ahead of schedule. This well is the longest single deployment production liner globally – 25,637 ft. and 4th Longest well drilled globally and longest well drilled in Middle east. In addition, production rate was as expected, confirming the anticipated non-damaging property of this OCF-IEF-RDF. The OCF-IEF-RDF was specially designed to deliver down-hole properties and behaviors that would deliver low ECD to Equivalent Static Density (ESD) margins. Without this superior control over ECD, the milestones above would not have been possible. It brought innovation to reality, which maximized returns by accessing reserves not easily accessible with conventional mud systems, drilling techniques, and saved on infrastructure costs. This increased reservoir drainage and resulted in significant productivity gains. Pushing the limit of this challenging condition can continue to break records in the future.

Although hydraulic fracturing is widely employed throughout most of the Middle East Region's carbonate reservoirs, it remains a relatively unused improved oil recovery (IOR) technique within the Emirate. Given the Company's goal to increase gas production, an in-country initiative was mandated to progress hydraulic fracturing of low permeability reservoirs. A multi-disciplinary project team was created and tasked to prove that hydraulic fracturing of a single horizontal lateral would give an improvement in well performance and value to that of the current technique of drilling open hole tri-laterals. The first step of the project to develop fracturing capability and best practices, required detailed up front planning by drilling a vertical pilot hole to collect data to build the mechanical earth model (MEM) and thus improve the fracture modeling and design. The challenges faced in the project so far were: Data sourcing, calibration and modelling. Low permeability sour gas reservoir with H 2 S and CO 2 around 7%. Gross reservoir thickness less than 50ft. and the absence of strong mechanical barriers to adjacent depleted reservoirs. Limited experience of hydraulic fracturing and conducting operations with a drilling rig. Zonal isolation for open hole multi-zone hydraulic fracturing in low permeability reservoirs. Technical and commercial processes for sourcing required equipment and optimising job execution. This paper will outline the strategies and tactics employed to implement fracturing in low permeability, thin, sour gas reservoirs, as well as the technical, operational, logistical and contractual challenges that have had to be overcome to date. The stated challenges and also that of operating under current restrictions due to global virus conditions will be described. The contents of the paper and subsequent material will build a Best Practice to successfully implement hydraulic fracturing operations in the Emirate.

After fast-tracking exploration success into an early production opportunity, Dubai Petroleum Establishment (DPE) recognized directional-casing-(and-liner)-while-drilling (DCWD) technology as enablers to optimizing the full field development of a thin oil rim within an interbedded steeply dipping reef build-up, just below the Nahr Umr Shale. The field development strategy was to land the well as close to the roof of the reservoir as possible and target the attic oil. This required entering the reservoir at higher inclinations and hence drilling the Nahr Umr Shale (cap rock for the reservoir) at more than 80° inclination. The regionally well-known borehole stability issues related to drilling the Nahr Umr Formation at high inclinations (and especially at azimuths that compound issues associated with in-situ stresses) presented a significant challenge for this field development. The objective of this paper is to share an innovative and successful solution which was implemented to mitigate or eliminate the potential issues associated with drilling operations through problematic and unstable formations at high angles (almost horizontal). An extensive engineering process was conducted involving different teams across the operator and the CWD service provider. The process included bottom hole assembly (BHA) drilling dynamics modelling using 4D time-based calculations and the typical drilling engineering calculations (torque and drag, hydraulics, alternating stress, etc.) to enhance the drilling performance during the drilling campaign. As an example, in one of the wells, the team drilled an interval in excess of 1200-ft, reaching the new world-record depth of 12,481-ft_MD, whilst meeting the operator's expectations in terms of rate of penetration (ROP), steerability of the directional BHA (achieving dogleg severity values higher than 4°/100ft), and flawless execution. The paper shows the methodology followed by the drilling team to evaluate the feasibility of the application, the challenges and lessons learnt, and the innovative solutions (telemetry, mud system, logging while drilling [LWD], motor design, underreamers, etc.) which were put in place to optimize the process over the course of the first six jobs in this new field. The DCWD technology enabled the well construction requirement of drilling an unstable shale on a high inclination trajectory (from 60° to 88° inclination), minimizing the stuck-pipe risk and typical unplanned time (NPT) associated with hard reaming, tight spots, and stuck pipe, and eliminating the additional 8 ½-in. hole requirement. The application allowed the operator to enhance the wellbore construction process and eliminated the requirement for an additional short 8.5-in. hole section, which then had to be cased off with a 7-in. liner to isolate the problematic formations. This represents a revolutionary change compared with the way that this challenge has been historically tackled by the operators in the Middle East (including limiting the inclination to a maximum 35°-40° or using oil-based mud [OBM] fluids with extremely high density that increases the chances of losses in the above formations, among others). The potential time savings due to the elimination of an additional interval to cover the problematic shale are estimated in excess of four days. In addition to the time savings, the operator has significantly reduced the associated cost for the BHA lost in hole (LIH) while drilling through the problematic shale without limiting the maximum inclination before landing in the target reservoir. This also creates a positive impact on the directional requirements for the horizontal-producing section (which can now be drilled in either 8 ½-in. and or 6-in. to address reservoir mapping and production conformance requirements).

When drilling in mature reservoirs, conventional formation evaluation is not enough. Characterizing these formations properly becomes essential in ensuring longer and sustainable oil producing boreholes. Understanding the geological complexities, permeability drivers and pressure potential is important since they control fluid flow. This work presents the first ever case study from the Abu Dhabi Carbonates where an innovative multi-measurement borehole imager was deployed, providing a comprehensive and integrated formation evaluation not used before in the industry. A campaign of five extended reach wells was planned in one field offshore of Abu Dhabi. A 15-ft long borehole imager was added to the drilling bottom-hole assembly (BHA) to acquire apparent resistivity and ultrasonic images simultaneously to characterize the often not-observed geological features that control reservoir properties. These complementing images helped in characterizing vug distributions, bioturbation, faults and dissolution seams in addition to the bed boundaries. Around 13,000ft of lateral was logged while drilling, using this data in real time in oil-based mud to target the most permeable and thinnest layers for the first time in the middle east. Core analysis had defined the 2ft thick most permeable layer of the reservoir where the lateral needed to be exposed for better production. Multi bed boundary detection for waterfront identification was integrated with mobility pretests points along with surface mud gas fluid sampling for Gas Oil Ratio (GOR) determination and the innovative dual imager. For the first time, acquiring a high resolution apparent resistivity image in real time in OBM, made the restriction of placing the lateral in a thin layer possible. Findings redefined the understanding of the geology and the drivers behind the fluid flow within this reservoir. With the new high definition ultrasonic image, vugs that tend to control the permeability in many facies were discovered. This led to the computation of a vug density curve derived from the images which characterized the key-intervals. Qualitative trends were validated with mobility estimated from independent LWD measurement, providing much-needed confidence in the new imaging technology. Completion was re-designed based on the new brought-in information. Sections were isolated based on the high-water saturation zones mapped with the multi bed boundary detection technology and higher gas oil ratio from surface fluid sampling. Completion was then optimized around high vug density/ mobility intervals. This first-ever case study provides a plethora of new information for model update whether it be the geology or the reservoir model that was hitherto unavailable for some reservoirs where development wells were drilled with OBM. For challenging wells planned in highly constrained environments from structure, petrophysics and reservoir maturity aspects, this new technology cleverly combined with others, opened the door to boost production from otherwise, a highly matured reservoir.

The last marine cycle of Dubai Lower-Cretaceous has left reefal carbonate deposits on paleo-highs from deep basement faults. Those shores face deposits at the edge of the former Bab basin and developed very good reservoir but had a prolonged emersion prior to the deposition of Nahr Umr seal and are often karstified. A successful development relied on high-angle drilling through an unstable seal and advance geosteering within a complex reservoir with a thin oil leg. A unique drilling approach in the region was designed and executed to deliver these wells safely. Oil- based mud (OBM), casing while drilling (CWD), and steering assembly were deployed to build safely in unstable shale and land at a high angle within the reservoir close to the roof in a relatively slim hydrocarbon column. The reservoir presents a succession of clinoforms. Good porosity and permeability streaks are present with tighter zones. Karsts, often linked with faults, represent a threat to drilling and well completion. The new high-definition reservoir mapping while drilling (RMWD) (6-in reservoir) was introduced to accurately steer within this reservoir. Simulations of drilling dynamics revealed the best BHA and casing designs. Over seven wells, this method was optimized by using an RSS and executing the 3D trajectory with required build rate and with no compromise on ROP. CWD was used to drill up to 12,481ft MD, which is the deepest in the world for such technology. Without it, inevitable slump down to the water leg would compromise the development of the entire field. The new RMWD technology revealed the reservoir details by mapping over 100 ft thickness of structure and fluid contacts. Subseismic Karsts and the irregular shale-carbonate contacts were precisely delineated. This allowed proactive reactions while drilling and avoided costly sidetracks. Clinoforms were resolved; transition zones and oil water contact depths were mapped. Over the course of seven wells, the information gathered allowed a redefinition of the entire field model from both a geological and reservoir perspective. As result, the original oil in place (OOIP) was recalculated with a renewed field development plan. The technical execution enabled the production of dry oil wells while steering as high as possible within the most permeable layers at a high rate, mitigating karst risk. The introduction of successful CWD eliminated the need to drill the 8^-in section. Four days were saved during the well construction process, and drilling risks associated with unstable and reactive shale were greatly reduced. The new RMWD technology in the lateral section potentially saved millions in development strategies and completion plans by mapping the complete oil column, transition, and water zones while providing safe geosteering away from karstic shales.

Stuck-pipe phenomena can have disastrous effects on drilling performance, with outcomes that may range from time delays to loss of expensive machinery. In this work, we develop three indicators based on the mudlog data, which aim to detect three different physical phenomena associated to the insurgence of a sticking. In particular, two indices target respectively the detection of translational and rotational motion issues, while the third index concerns the wellbore pressure. A statistical model that relates these features with the documented stuck-pipe events is then developed using machine learning. The resulting model takes the form of a depth-based map of the risk of incurring into a stuck-pipe, updated in real time. Preliminary experimental results on the available dataset indicate that the use of the proposed model and indicators can help mitigate the stuck-pipe issue.