This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203147, “Investigating Hole-Cleaning Fibers’ Mechanism To Improve Cutting Carrying Capacity and Comparing Their Effectiveness With Common Polymeric Pills,” by Mohammad Saeed Karimi Rad, Mojtaba Kalhor Mohammadi, SPE, and Kourosh Tahmasbi Nowtarki, International Drilling Fluids, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Hole cleaning in deviated wells is more challenging than in vertical wells because of the boycott effect or the eccentricity of the drillpipe. Poor hole cleaning can result in problems such as borehole packoff or excessive equivalent circulating density. The complete paper investigates a specialized fibrous material (Fiber 1) for hole-cleaning characteristics. The primary goal is to identify significant mechanisms of hole-cleaning fibers and their merits compared with polymeric high-viscosity pills. Hole-Cleaning Indices Based on a review of the literature, most effective parameters regarding hole cleaning in different well types were investigated. These parameters can be classified into the following five categories: - Well design (e.g., hole angle, drillpipe eccentricity, well trajectory) - Drilling-fluid properties (e.g., gel strength, mud weight) - Formation properties (e.g., lithology, cutting specific gravity, cuttings size and shape) - Hydraulic optimizations (e.g., flow regime, nozzle size, number of nozzles) - Drilling practices (e.g., drillpipe rotation speed, wellbore tortuosity, bit type, rate of penetration, pump rate) In this research, rheological parameters and parameters of the Herschel-Bulkley rheological model are considered to be optimization inputs to increase hole-cleaning efficiency of commonly used pills in drilling operations. The complete paper offers a detailed discussion of both the importance of flow regime and the role of the Herschel-Bulkley rheological model in reaching a better prognosis of drilling-fluid behavior at low shear rates. The properties of the fibrous hole-cleaning agent used in the complete paper are provided in Table 1. Test Method Two series of tests were performed. The medium of the first series is drilling water, with the goal of evaluating the efficiency of Fiber 1 in fresh pills. The second series of tests was per-formed with a simple polymeric mud as a medium common in drilling operations. Formulations and rheological properties of both test series are provided in Tables 4 and 5 of the complete paper, respectively.

A blowout in Ohio in 2018 was the first ever where the emissions could be measured from space, though it was at best a rough estimate based on data gathered on the 13th day after the XTO Energy well control event began. A year later, a blowout of a Devon well near Victoria, Texas, was measured starting the day after it occurred, with data collected on 3 days over the next 2 weeks. Using the measurement of carbon dioxide, it was estimated that the flare was 87% effective in burning about 4,800 metric tons of the leaking methane gas. Emission estimates varied wildly, and both the Ohio (Pandey et al. 2019) and Texas (Cusworth, Duren, Thorpe et al. 2020) efforts to use satellites led to technical papers to consider how they addressed this challenge. For those with blowouts next year, chances are a lot better methane-emission data would be available because of the launch of a constellation of specialized methane-measurement satellites by the two groups that played a key role in the earlier tests. In presentations at CERAWeek by IHS Markit, GHGSat said it has two methane-detection satellites in orbit and plans the launch of eight more, and the Environmental Defense Fund (EDF) said it is moving forward with the launch of its first one next year. Both are aiming to cover the lion’s share of oil and gas operations and measure the flow rate of the gas rather than concentrations in the atmosphere. They said they can do that far more accurately than was possible with the general-purpose climate observation satellites by focusing their equipment on the wavelength of methane. GHGSat said its satellites, which are about the size of a microwave oven, can measure the potent greenhouse gas from an elevation of 500 km and up. They are placed in polar orbit, which allows them to cover the globe every 2 weeks as the Earth rotates. Launching more satellites will allow more frequent looks. There are differences in the GHGSat and EDF designs, reflecting their contrasting missions. The Canadian company GHGSat, whose satellite initiative was initially supported by Schlumberger and the Oil and Gas Climate Initiative, is building tiny satellites with extremely high resolution to serve clients in the oil and mining businesses. During the presentation, Stéphane Germain, chief executive officer of GHGSat, displayed an image and said its satellites can tell if the methane is “coming from a particular facility and even tell what part of the facility it is coming from.” The company also sells the services of similarly equipped planes that can create more-detailed images using similar equipment at elevations of 3000 m and higher. EDF raised $100 million from donors, including Elon Musk, and has hired Raytheon to build a satellite equipped with a detector from Ball Aerospace. It can survey an area that is 260 km wide. That is far wider than the GHGSat satellites, which have the advantage of being able to zero in on smaller details when looking for leaks. The environmental group points out its device is more sensitive to methane emissions, detecting levels down to two parts per billion.

Background Field trials using a new scale-inhibitor technology that improves treatment lifetime of scale squeezes have been successfully performed in the Gulf of Mexico. Tomson Technologies, in partnership with Shell, developed proprietary nanoparticle carriers that enhance scale-inhibitor adsorption to the reservoir and control the return rate for extended periods of time. This technology results in less chemical bleed off in the initial flowback and increases the chemical retained in the reservoir, allowing for more effective squeeze treatments. Both nanoparticle-enabled phosphonate and polymer inhibitors have now been developed and successfully squeezed in the field. Phosphonate inhibitors are widely used for squeeze treatment due to their desirable adsorption and release properties in carbonate and sandstone reservoirs. Minor changes have been made to the chemistry, but overall, the fundamentals have remained unchanged for decades. Polymeric scale inhibitors have also been developed for cases in which phosphonates are not applicable. The nano-enhanced technology provides a large improvement of treatment lifetime of 2 to 4 times (200-400%) when compared to incumbents, making this technology advancement attractive even in cases where current squeezes are considered successful. The well selected for this case study is an offshore formation with a predominantly sandstone mineralogy (approximately 80% quartz) with 25-30% porosity and bottomhole temperature of 183°F (83°C). Technology From the Lab to Field A sandpack sample from the trial well was used in the laboratory to deter-mine the adsorption and desorption properties of the nano-enabled inhibitor in realistic rock conditions. Multiple conditioning steps were used before product was injected in a sequence that mimicked field squeeze treatments. Mass-balance results from the sandpack experiment show adsorption of approximately 8 mg of polymer retained per gram of crushed reservoir rock used in the experiment. A typical rule of thumb for phosphonate-scale inhibitors (only as a comparison since this is a polymeric scale inhibitor) is 1-2 mg of inhibitor retained per gram of rock. Therefore, this is considered a large improvement on adsorption. There are challenges associated with measuring polymers in brine as residuals; however, multiple methods, both in-house and external, were com-pared to ensure accuracy. The results using the nano-enhanced scale inhibitor show concentrations higher than 1 mg/L of active polymer for over 7,000 pore volume of return in the sandpack experiment. Complete intact core experiments were also conducted with reservoir fluids and showed no formation damage during the injection of the product with regained oil permeability of 96%. Oil permeability was in the 150-200 mD range for the intact core experiments. Third-party coreflood testing was performed with nitrified and foamed stages to ensure compatibility with the nano-enabled chemistry. No formation damage was observed with the nitrification of the stages containing the nano-enabled chemistry. Field Application Case Study After extensive lab validation of the product and supporting corefloods to de-risk the technology, Well A was selected by Shell to be the first well treated with the new nano-enabled extended-lifetime inhibitor.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200588, “Fracturing With Height Control Extends the Life of Mature Reservoirs: Case Studies From the Pannonian Basin,” by Ruslan Malon, SPE, Independent, and Jonathan Abbott, SPE, and Ludmila Belyakova, SPE, Schlumberger, et al., prepared for the 2020 SPE Europec featured at the 82nd EAGE Conference and Exhibition, originally scheduled to be held in Amsterdam, 1-3 December. The paper has not been peer reviewed. Hydraulic proppant fracturing is an effective tool in mature, low-permeability reservoirs found in the Pannonian Basin. However, for wells already producing with high water cut, even a small fracture extension into a water-bearing zone offsets the gains in hydrocarbon production. Fracture-geometry-control (FGC) techniques limit increases in water cut. The complete paper describes the first implementation of a solution to control fracture height for conventional wells in the Pannonian Basin. An integrated engineering approach was applied, including a new proppant-transport model to predict fracture geometry improvement using the FGC solution. Decreased Recovery in A and B Fields Oilfield A began producing in 1984. In addition to an interruption by the war in Yugoslavia in the 1990s, production has been in decline, and most wells are at risk of being shut in because of low production rates. During the last 10 years, propped fracturing was integrated into the production strategy for this mature field. Field A comprises Lower Pontian (Miocene) sandstones. Another sandstone formation exists between 5 and 15 m below the production target reservoir, with high water saturation as confirmed by log analysis and well testing. The proximity of the oil target to the water-bearing interval still presents a risk to production considering that hydraulic fracturing is required to extend field life. An impermeable shale streak that may act as a geomechanical barrier exists below the target formation. With a lower risk of fracture propagation into the water zone, Field A was one of the first candidate fields for propped fracturing and was later considered for advanced fracture-height-control techniques to prevent the increase of water cut after stimulation. Hydraulic fracturing would not be trialed in Field B—the characteristics of which are provided in the complete paper—until the advanced height-control techniques had been proved on the basis of experience with Field A. Oilfield A: Early Fracturing Results Early campaigns proved the economic feasibility of propped fracturing, resulting in a 2.1-fold average increase in oil production during the first 6 months of production. Unfortunately, production after this early period declined rapidly. Increases in water cut, seen in several fracturing campaigns, clearly were related to hydraulic fracture growth. Although the resulting uplift in oil production warranted continued fracturing, avoiding water was a key issue to address before expansion of propped fracturing further in this field and to other fields with an even higher risk of water.

Anyone who works in the oil and gas industry is aware of hydrogen sulfide (H 2 S) gas. This is a highly toxic gas that gives rise to “sour” production. H 2 S is highly corrosive to many common materials used by the industry (e.g., mild steels), and there often are strict fiscal and technical limits placed on upstream oil and gas producers by the midstream and downstream operators. The origin of H 2 S can be authigenic (i.e., occurs in-situ and naturally in the reservoir, related to the biological origin of the organic matter that produces the crude oil and gas), or it can be caused by biological processes and the action of sulfate-reducing bacteria (e.g., during seawater flooding and contamination of the reservoir). The concentration range of H 2 S that occurs can vary from a few parts per million (ppm) to many tens of percent of the raw gas production. The range of concentrations that may be treated economically by chemical H 2 S scavengers is typically up to 5,000 ppm (0.5%). Higher concentrations may be treated by other means such as amine recycling unit sequestering systems. The industry has relied upon the triazine family of chemistry for several decades as the mainstay scavenger for H 2 S (originally patented in the 1990s), and the understanding of the application parameters and reaction byproducts has grown over the years. There is, however, still much to understand, and, even recently, several significant advancements have occurred, many focusing on some of the understood challenges of using triazine chemistry. The featured papers and suggested further reading summarize the current SPE literature state of the art for H 2 S scavenger research and development and have been selected to give readers a broad indication from both academia and industry around the world.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper NACE 2019-13401, “Effects of Triazine-Based H 2 S Scavenger Byproducts on the Film Composition and Cracking of Carbon Steel in Oilfield Applications,” by Leonardo Caseres, James Dante, and Florent Bocher, Southwest Research Institute, et al., prepared for the 2019 NACE International Corrosion Conference and Exposition, Nashville, Tennessee, USA, 24-28 March. This paper has not been peer reviewed. Triazines are commonly used as hydrogen sulfide (H 2 S) scavengers. However, stress corrosion cracking (SCC) has been reported recently when using certain triazines, making it necessary to understand the failure mechanism to control this phenomenon. In the complete paper, the authors seek to understand the effect of triazine on the electrochemical response of a carbon-steel surface in a mixed-gas system. Introduction One of the more frequently used H 2 S scavenger triazines is hexahydro-1,3,5-tris(hydroxyethyl)-s-triazine, or monoethanol amine (MEA)-triazine. It is a yellow, viscous liquid that can be injected into gas streams or used in a contactor tower. It removes H 2 S from the gas stream. It is relatively inexpensive, easy to use, and effective. The MEA byproducts that form during the scavenging process, however, may cause SCC of steel pipes, as reflected in the literature. On the basis of these findings, it is suggested that SCC is governed by corrosion processes and specifically by the transition from a passive to an active surface. This transition is a complicated function of acid gas concentration [carbon dioxide (CO 2 ) and H 2 S] and amine adsorption, which are likely different for different systems. Several possible mechanisms exist by which cracking can be induced. First, a reduction in H 2 S content can reduce the semiprotective iron-sulfide film, thus changing the nature of the active/passive transition and making cracking more likely. Second, specific adsorption of amines onto the surface of the steel will result in a change in the active/passive transition. Therefore, characterization of the MEA/H 2 S reaction process, the adsorption of amines onto steel, and the electrochemical behavior of the steel under these circumstances are important factors that require study. In this paper, the electrochemistry of API X601 steel is assessed under a variety of test solutions containing H 2 S, CO 2 , and MEA triazine. Environmental Conditions The specimens were 0.25 in. in diameter and 4 in. long. Approximately 3 in. of the specimen length was exposed to the solution. All electrochemical tests were conducted at room temperature and atmospheric pressure. Three gas mixtures were employed: 20-ppm H 2 S balanced with dinitrogen (N 2 ), 20-ppm H 2 S/2 mol% CO 2 , and 100% N 2 . In addition, three triazine-inhibitor (35% triazine concentration solution) volumetric additions were used. The actual inhibitor concentrations in solution were not determined; instead, the H 2 S concentration in the gas phase was measured with a sensor after the addition of the inhibitor. The supporting electrolyte [0.1-M potassium chloride (KCl)] solution was deaerated N 2 gas.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194689, “Challenges in Selection and Use of Production Chemicals With Chemical EOR Operations During Polymer Breakthrough Phase,” by Robert Zagitov, Panneer Selvam Venkat, and Ravindranthan Kothandan, Cairn Oil and Gas, et al., prepared for the 2019 SPE Oil and Gas India Conference and Exhibition, Mumbai, 9-11 April. The paper has not been peer reviewed. In chemical enhanced oil recovery (EOR), challenges are expected regarding production chemistry and production-facilities operations. Partially hydrolyzed polyacrylamide (HPAM) is used widely for controlling mobility ratios. Complex in water chemistry and rich in positively charged divalent ions, flooded polymer, having a negative charge, interacts with divalent ions of produced water (PW). The complete paper discusses the importance of adequate preparation and the approaches used to overcome challenges of EOR operations, including handling back-produced polymer. Introduction The Mangala field in northwest India, discovered in January 2004, is part of the Barmer Basin. The primary reservoir unit in this field is the Fatehgarh group, a high-quality quartzose sandstone reservoir having high net-to-gross ratio, high porosity (21-28%), and multidarcy permeability (200 millidarcy to 20 darcy) with an average permeability of approximately 5 darcy. The reservoir contains waxy crude with gravity ranging from 20 to 28 °API. A primary recovery efficiency of less than 10% stock-tank oil initially in place is estimated on the basis of simple depletion; thus, the base field-development plan envisaged implementation of waterflooding from the start of production to maintain reservoir pressure and sweep reserves. Detailed laboratory studies have established that aqueous-based chemical EOR processes are best suited for these viscous oil fields. Full-field polymer flooding has been implemented in the Mangala field, with an injection at the time of writing of nearly 400,000 B/D of polymerized injection water (IW) with average polymer concentration of approximately 2,500 ppm. HPAM is mixed with source water to create a mother solution of 15,000-ppm concentration at a central polymer facility and is distributed through a pipeline network to 15 well pads, where it is diluted with IW to achieve a viscosity of approximately 30 cp for injection. Artificial lift is achieved either by jet pump or electrical submersible pump. Average water cut is 80% at the time of writing.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193564, “Scale Prediction and Mineral Solubility Under HP/HT Conditions,” by David Nichols, Neil Goodwin, and Gordon Graham, SPE, Scaled Solutions, et al., prepared for the 2019 SPE International Conference on Oilfield Chemistry, Galveston, Texas, 8–9 April. The paper has not been peer reviewed. Accurate scale-prediction modeling is only possible when reliable mineral solubility data are available under the required conditions. It is recognized that the relative paucity of high-pressure/high-temperature (HP/HT) solubility data can result in inaccurate predictions because current models extrapolate from data obtained under more conventional conditions. The complete paper describes the generation of additional fundamental solubility data under HP/HT conditions and comparison of the obtained values with several existing models. Introduction The limited availability of HP/HT mineral solubility data in simple brine conditions and the paucity of solubility data in complex brine systems means that existing scale-prediction models, including those used in conventional software in common industry use, are forced to extrapolate, resulting in inaccurate and potentially misleading predictions. Efforts have been made in recent years to address this issue by generating additional solubility data under HP/HT conditions to allow improved models to be developed. It is apparent from the reported work, and comparisons with previous literature, that these measurements are not trivial and require detailed understanding, development, and validation to ensure that reliable measurements are obtained. However, full details, comparison, and verification of the various experimental methods used are rarely presented and discussed, particularly in older works. The experimental method used must demonstrate that equilibrium solubility has been reached, preferably in a reasonable laboratory time period. The complete paper discusses the experimental considerations that must be taken into account when generating HP/HT solubilities, and presents methods to confirm that true equilibrium conditions have been reached. Experimental Methods Solubility measurements were made using a purpose-built laboratory test rig capable of attaining 250°C and 30,000 psi, though data described here were obtained between 50 and 200°C and between 10,000 and 19,000 psi. The design and validation of this rig against literature data has been previously described in detail in paper SPE 184568, and is only presented in summary in the complete paper. A schematic of the apparatus is shown in Fig. 1, while Fig. 2 shows the pressure vessel used in the system. Results There are two primary experimental approaches that can be applied, and both have been investigated in the course of this work, using the same combined flow-through and static method. The first is to approach equilibrium from below by dissolving the test mineral into the brine composition of interest. In the second, the precipitation approach, a mixture of two fluids, one containing the relevant cation and one the corresponding anion, are mixed to create a solution oversaturated slightly in the test mineral before being applied to the sample. This seeding is intended to result in crystallization of the excess solute, relieving the supersaturation and resulting in a solution containing equilibrium concentration of the mineral under the chosen conditions. However, the rate of the dissolution and precipitation processes can vary considerably for a given mineral and, if this is not recognized, inaccurate solubility measurements will result.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193238, “Investigation of Smart Waterflooding in Sandstone Reservoirs: Experimental and Simulation Study, Part 2,” by Hasan N. Al-Saedi, SPE, Missouri University of Science and Technology and Missan Oil Company; Ralph E. Flori, SPE, Missouri University of Science and Technology; and Alsaba Mortadha, Australian College of Kuwait, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, 12–15 November, Abu Dhabi. The paper has not been peer reviewed. In this paper, the authors consider the effect of water chemistry on water/rock interactions during seawater and smart waterflooding of reservoir sandstone cores containing heavy oil. Oil recovery, surface-reactivity tests, and multicomponent reactive-transport simulation were conducted to understand smart waterflooding better. The authors determine that lowering magnesium-ion (Mg 2+ ) concentration results in lower additional oil recovery, and that lowering calcium-ion (Ca 2+ ) concentration leads to higher additional oil recovery. Introduction “Smart water” (SW) can be defined as a water engineered by manipulating the ionic composition (adding or removing ions) regardless of the resulting salinity. An upward pH shift has been reported in the literature during low-salinity (LS) and/or smart waterflooding. That upward shift modifies the wettability of sandstone, thereby increasing oil recovery. When high salinity is displaced by LS water, Ca 2+ will be desorbed from the clay surface because ion exchange occurs between hydrogen (H + ) and Ca 2+ at the negative sites of the clay surface. The organic materials will be then desorbed from the clay because of the reaction between the protonated basic and the acidic materials with hydroxide. The authors’ investigations on free-clay sandstone provided a different insight into such reactions. The observations from chromatographic columns of quartz showed an increase in the acetate detachment from the quartz surface with a significant pH jump during LS waterflooding. The oil-recovery observations from the quartz column supported the proposed mechanism. Previous systematic laboratory works indicated that the abundance of Mg 2+ in the formation water (FW) is more effective than Ca 2+ for a higher LS enhanced-oil-recovery (EOR) effect. Conversely, the abundance of Ca 2+ in the injected LS water has a larger effect on LS EOR. When Mg 2+ was present in the LS water, no oil-recovery improvement occurred. Methodology Brines. Synthetic FW and SW were prepared by dissolving sodium chloride (NaCl), calcium chloride (CaCl 2 ), and magnesium chloride (MgCl 2 ) in deionized water. Crude Oil. A reservoir crude oil was de-livered from eastern Kansas from the Bartlesville sandstone reservoir. The crude oil had a viscosity of approximately 600 cp at ambient temperature. The density is 0.83 gm/cc at 20°C. Reservoir Rock Description and Core Preparation. Five Bartlesville sandstone reservoir cores were drilled from the original 3-in. diameter to a 1-in. diameter preserved core from eastern Kansas. The preserved reservoir sandstone cores were delivered with 3-in. diameter. The most abundant mineral was quartz, followed by clays.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19342, “Design and Evaluation of a Water-Based Drilling-Fluid Formulation Using SIO2 and Graphene Oxide Nanoparticles for Unconventional Shales,” by Jose Aramendiz, SPE, Abdulmohsin H. Imqam, SPE, and Sherif M. Fakher, SPE, Missouri University of Science and Technology, prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. Traditionally, oil-based drilling fluids are preferable in drilling shale plays because of their negligible chemical interactions, but strict environmental regulations have motived the industry to design water-based muds (WBMs) capable of controlling shale/water interactions. Still, conventional additives in general are too large to plug shale microfractures and nanopores. Thus, nanoparticles, because of their size, shape, and other properties, can provide a solution for WBMs. This study focus on the design and evaluation of a customized water-based mud (NP-WBM) using silica oxide nanoparticles (SiO 2 -NPs) and graphene oxide nanoplatelets (GNPs). Experimental Description Experimental Materials. Conventional Drilling-Fluid Additives. The micro-size additives used in this work included bentonite to provide primary viscosity and xanthan gum to adjust the final rheological properties of the base fluid. Polyanionic cellulose low- viscosity and pregelled starch were included as conventional filtrate-loss additives. Graphite was used as conventional lost- circulation-material (LCM) additive. Potassium hydroxide was included as an alkalinity-control agent. Nanomaterials. SiO 2 -NPs were supplied in a white powder form. The SiO2-NPs are near-spherical with an approximate diameter ranging between 15 and 20 nm. The NPs were unmodified (bare surface) and nonporous with a density of 0.1 g/cm 3 , a specific surface area of 170–200 m 2 /g, and purity greater than 99.5 wt%. GNPs used in this study had a density of 0.13 g/cm 3 . The GNPs have a 2D structure with an average particle size ranging from 1.3 to 2.3 µm and a thickness of less than 3 nm. Shale Rock Properties. Woodford shale was used to test the effect of using NPs to enhance the inhibition capabilities of WBM. This rock is described as a late Devonian-Early Mississippian marine shale. In this study, shale samples of 1 in. in diameter and lengths between 0.5 to 2 in. were cored and stored in high-purity mineral oil to avoid property alterations. The rock contains 31.5% clay minerals (22.8% illite, 5.4% chlorite, and 3.3% kaolinite), 67% quartz, and 1.5% pyrite, indicating a high degree of brittleness as well as low water sensitivity. Fig.• 1 shows a sequence of scanning electron microscope (SEM) images in which Image A is equivalent to 7,000x magnification and Image B shows a 30,000x magnification with respect to the original sample size. The SEM images suggested a pore-size distribution between mesopores (2–50•nm) and macropores (greater than 50 nm) with an estimated median pore size of 112.84 nm. Therefore, the nanomaterials in this study have a scale matching that of the Woodford shale and can be used as theoretical bridging agents.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 191598, “Enhanced Flux Management for Sand-Control Completions,” by John Cameron, SPE, Karim Zaki, SPE, Colin Jones, SPE, and Antonio Lazo, SPE, Chevron, prepared for presentation at the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September 2018. The paper has not been peer reviewed. This paper discusses a probabilistic flux and erosion model and work flow that extend the ability to estimate inflow through sand screens on a foot-by-foot basis along the wellbore using the well’s completion details, production rate, and reservoir and bottomhole flowing pressures. The model is then calibrated and history matched using well data from pressure transient analyses, well tests, and production logs as available. Extensive laboratory testing coupled with computational flow dynamics modeling provided the algorithms for different screen types to relate flux and sand production to the expected service life for any given future production profile. This allows the well’s planned production profile to be optimized by balancing risk, rate, and reserves recovery. Introduction The flux management work flow was field trialed on various failed and successful sand-control completions and has been used on many wells subsequently. It has been applied to wells currently on production by history matching to track current erosion levels and then to predict future erosion or time to failure. Failure here is taken to mean a loss of sand control, typical higher rates of sand with large particles and proppant. The work flow can also be applied to planned wells to help optimize the completion design. The work flow is currently being adapted to be applied to producing wells in real time. When compared with conventional flux limit models, the work flow drives increased production while the risk of sand production is low and where the completion quality is good. Conversely, where pack quality is low or uncertain and sanding information is of low quality, the work flow can result in a comparative reduction in the allowable rates. The prediction uncertainty ranges reflect the quality of the input information and are driving improvements to the measurement of completion quality and sand production as well as to new, cost-effective, erosion-resistant screen designs. The new work flow considers pack quality and sand production (particle size, type, and concentration) and allows an operator to maximize well economics by optimizing the production profile for rate, reserves recovery, and service life. Conventional screen erosion models, on the other hand, do not consider a sand-control screen’s erosion history and future service life. Historical Perspective and Review Sand-control failures can be caused by installation damage, compaction, corrosion, or improper deployment or inappropriate system selection. The complete paper presents a historical perspective and review of these failure mechanisms and methods of addressing them and includes a discussion of fluid velocities and constraints. Enhanced Flux Management Work Flow Conventional erosion models are aimed at calculating fluid-velocity limits and ensuring that the fluid velocity is constrained to below these limits at all times.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191864, “Aggressive or Not? Experimenting With Fracturing Design and Fluids in Pursuit of Better Returns,” by Max Nikolaev, SPE, Haiyan Zhao, Yenny Christanti, SPE, and Sergey Makarychev-Mikhailov, SPE, Schlumberger, prepared for the 2018 SPE Argentina Exploration and Production of Unconventional Resources Symposium, Neuquén, Argentina, 14–16 August. The paper has not been peer reviewed. The authors examine methods of adopting an aggressive approach to optimizing stimulation design to lower the breakeven level of operations and evaluate the results. Operators achieved significant improvements in production by changing parameters in the fracturing and completion design strategy, including, but not limited to, the amount of water used, the amount of sand pumped, stage spacing, maximum sand concentration, and fracturing-fluid selection. The complete paper addresses the importance of aggressive design, its evolution, and its enabling technologies. Trends in Development of Unconventional Resources Although completion practices and production numbers vary from basin to basin and from play to play, certain high-level trends remain in the development of unconventional reservoirs over the past few years. In most places, operators have been drilling increasingly longer laterals. Although public fracturing-stage-count information is scarce, internal service-company data still show a continuous increase in stage count and, in certain plays, an increase steeper than the increase seen in perforated intervals. Cased-hole completions with more than 50 stages per well are becoming common in all basins, thanks to the improved efficiency of fracturing and plug-and-perf•operations. At the same time, fracturing treatment sizes have grown even faster than have perforated intervals and stage counts. Median proppant volumes have nearly tripled during the past 5 years. The stimulation fluid volumes increased nearly proportionally to proppant volumes. Slickwater (SW) has become a fluid of choice in most plays, thanks to its operational simplicity and low cost. Hybrid treatments also remain popular; in these approaches, a high-viscosity crosslinked fluid, usually guar-based, often is pumped at the end of a treatment to deliver higher proppant concentrations and effectively prop the near-wellbore area. The number of higher-cost and operationally more-complex crosslinked fluid-fracturing jobs has decreased as placement of large amounts of proppant with crosslinked jobs becomes uneconomical. Longer laterals, better wellbore coverage, and significant amounts of fracturing materials enable increased well productivity in most plays. Production here is expressed in barrels of oil equivalent, calculated on the basis of relative cost, with 20 Mscf equal to 1 bbl of oil. Median production volumes, normalized by 1,000 ft of perforated interval, still demonstrate substantial increase over time. However, with production normalized by 1,000,000 lbm of proppant, or by proppant density per perforated interval, the trends turn negative, indicating diminished returns with further increase of proppant volumes per well.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194362, “Understanding Fracturing-Fluid Distribution of an Individual Fracturing Stage From Chemical Tracer Flowback Data,” by Wei Tian and Alex Darnley, SPE, ResMetrics; Teddy Mohle, SPE, and Kyle Johns, Contango Oil and Gas; and Chris Dempsey, ResMetrics, prepared for the 2019 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, 5–7 February. The paper has not been peer reviewed. This paper presents a data set involving the pumping of multiple, unique chemical tracers into a single Wolfcamp B fracture stage. The goal of the tracer test is to improve understanding of the flowback characteristics of individually tagged fluid and sand segments by adding another layer of granularity to a typical tracer-flowback report. The added intrastage-level detail can provide insights into fracture behavior in shale-reservoir stimulation by looking at individual fluid-segment tracer•recoveries. Introduction Operators have relied upon high-intensity completion designs that include a combination of high proppant volumes, increased perforation-cluster density, and smaller-mesh-size proppants. These designs aim to create a complex fracture network and increase the contact area with shale rock. They have helped operators achieve higher initial productivity and larger estimated ultimate recovery while simultaneously enabling the drilling of horizontal wells at tighter well spacing. The traditional, bi-wing fracture model seems to be scrutinized increasingly for its lack of relevance when stimulating shale reservoirs. Operators have observed greater fracture complexity when using enhanced completion designs. These designs aim to increase fracture surface area and complexity, leading to a debate regarding the merits of stimulated reservoir volume (SRV) and propped-stimulated reservoir volume, also known as effective propped volume (EPV). SRV, estimated usually from micro seismic mapping, is a rough estimate of the volume of rock that is hydraulically fractured, and is sometimes defined as the product of gross stimulated area and pay-zone thickness. EPV is a fraction of the total SRV that is supported by proppant and is capable of flowing during depletion. From a production perspective, the surface-area contact of the fractional propped SRV is more important than the gross SRV estimate. In the past, chemical tracer data have offered stage-level insights into load recovery and hydrocarbon contribution, but the data set presented in the complete paper considers individual fluid-segment data within a single fracturing stage. A few of the questions prompting this study included: Do certain fluid segments exhibit poor tracer recovery by being placed within the unpropped fraction of the SRV? Does the order of injected fracturing fluid correspond with the order in which tracer is produced? Can the residence-time calculation for each tracer be used to infer the degree of fracture complexity? As operators elect to enhance fracture complexity by increasing perforation-cluster density, using lower-viscosity-fluid systems, and pumping smaller-mesh proppants, the modeling of fracture geometry has proved difficult. In addition, varying perforation-cluster efficiency and sand-duning effects can cause fluid and proppant to be distributed nonuniformly within the fracture network.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 28578, “Quantitative Ranking and Development of Hydrate Antiagglomerants,” by Shane A. Morrissy, Temiloluwa O. Kuteyi, Mike L. Johns, Eric F. May, SPE, and Zachary M. Aman, SPE, University of Western Australia, and Stuart F. McKay, SPE, Woodside Energy, prepared for the 2018 Offshore Technology Conference Asia, Kuala Lumpur, 20–23 March. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. A common hydrate-management strategy involves the use of large volumes of thermodynamic inhibitors (THIs) to operate outside the hydrate-stability region. However, this strategy represents significant capital expenditure and operating costs. Low-dosage hydrate inhibitors (LDHIs), in the form of kinetic hydrate inhibitors (KHIs) and antiagglomerants (AAs), present an economical alternative to THIs. In this study, a quantitative micromechanical force (MMF) has been deployed to study the performance of seven industry AAs. The results illustrate that an effective AA is one that lowers the cohesive forces between hydrate particles. Introduction AAs prevent hydrate agglomeration of a steady-state hydrate slurry. Hydratephilic AAs are surfactants that adsorb to the hydrate/oil interface in preference to the water/oil interface. Current operating experience suggests that AAs may be unsuited to the high water cuts that are characteristic of late field life. A successful hydrate AA lowers the cohesive force or surface free energy of hydrate particles to prevent agglomeration. Rocking cells and high-pressure visual autoclaves provide a semiquantitative assessment of hydrate blockage. However, a knowledge gap exists with regard to whether current industry AAs actually lower hydrate interparticle cohesive and surface free energy. Techniques to deconvolute the mechanism of the action of AAs are required to better understand how AAs affect hydrate blockage. Experimental Procedure Micromechanical Hydrate Cohesive Force. A third-generation MMF apparatus was used to measure the cyclopentane hydrate interparticle cohesive force. The MMF uses cyclopentane to create Structure II cyclopentane hydrates, the same hydrate structure present in the field. The cohesive-force-measurement technique was adapted from previous re-search on hydrate cohesion and asphaltene cohesion. Interfacial Tensiometry. An optical interfacial tensiometer was used to measure the interfacial tension (IFT) between water and oil phases at ambient pressure and room temperature. A hooked needle with the AA prepared in paraffin oil was placed in a bulk phase of deionized water. The resolution of this apparatus is typically +- 1 mN/m and the threshold sensitivity is 1 mN/m. Typically, surfactant-free systems will rap-idly reach equilibrium within 1 minute of creating an oil droplet in water. Conversely, the presence of a surfactant may decrease the IFT as a function of time, asymptotically approaching a steady-state value. Because the AAs studied contain surfactant functionality, each IFT was measured for at least 20 minutes, after which point the IFT was not observed to change with time. Each data point represents an average of at least four independent trials.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of “Mitigation of Scaling Potential of Seawater in High-Temperature Environment Using Phosphonate Scale Inhibitor,” by Raafat M. Yamak and Hisham Nasr-El-Din, SPE, Texas A&M University; Sabiq Rahim, SPE, Halliburton; and Moussa Taleb, University of Calgary, prepared for the 2019 SPE Kingdom of Saudi Arabia Annual Technical Symposium and Exhibition, Dammam, Saudi Arabia, 16–18 April. The paper has not been peer reviewed. In this study, a laboratory analysis was conducted to study the effect of a phosphonate-based scale inhibitor on a mixture of hypersaline Arabian Gulf seawater and formation water under high-temperature/high-pressure conditions. The objective was to identify the minimum scale-inhibitor concentration required at various temperatures to achieve a cost-effective solution in minimizing the formation of common oilfield scales. This research pushes the thermal constraints of a phosphonate-based scale inhibitor to 330°F to test its efficiency and treatment integrity. Introduction Produced water, seawater, and nanofiltered seawater have been explored as environmentally friendly and cost-effective alternatives to fresh water in fracturing fluids at different ratios. Consequently, total-dissolved-solids (TDS) levels, salinity, and bottomhole temperatures have increased, making scale inhibitors more important than ever. In this study, raw Arabian Gulf seawater and a water mixture from the Jafurah formation was used at various ratios and at different temperatures to determine the efficiency of a phosphonate-based scale inhibitor in the presence of ion complexes. High scale formation was associated with the ionic effect on the fluid, especially because of the high content of sulfate in seawater and high barium and calcium concentrations in connate water. Scale-advisory-software results indicated that barium sulfate was the major scale. Additionally, specific ions can affect the pH of the fluid severely, thereby inhibiting the operational function of the buffer systems. Scaling is a natural byproduct of seawater-based fracturing. As a result, various water treatments have been implemented to decrease scale formation. One such method involves nanofiltration. Experimental results have shown that nanofiltration caused sulfate reduction in seawater sources down to 300 ppm. This lowers the scaling tendency to a point at which it is controllable by conventional chemical treatments. To address the issue of freshwater scarcity and associated treatment costs of alternatives such as waste water, the use of raw seawater has received attention. The TDS content of the source water used in this paper is one of the highest in the world, given that the Arabian Gulf is known for its hyper-saline conditions. Furthermore, the cations present in the water, namely calcium and magnesium, are known to cause problems in the formulation process of hydraulic-fracturing fluid. As a result, it is expected that certain fracturing-fluid additives must be increased to meet these challenges and ultimately create a stable seawater-based fracturing-fluid system with appropriate gelation timing that meets industry standards. This study aims to find an alternative source to freshwater-based fracturing fluid and contribute to the study of scale inhibition as dirtier water sources are considered.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189569, “Fines Migration During CO2-Saturated Brine Flow in Carbonate Reservoirs With Some Migratory Clay Minerals—Malaysian Formations,” by Y. Sazali, Petronas; S. Godeke, SPE, Universiti Brunei Darussalam; W.L. Sazali and J.M. Ibrahim, Petronas; G.M. Graham and S.L. Kidd, Scaled Solutions; and H.A. Ohen, SPE, HPO Global Resources Ventures, prepared for the 2018 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 7–9 February. The paper has not been peer reviewed. A high-carbon-dioxide (CO 2 ) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development. Reservoirs in this region have an average clay content of 8%; more than 50% of this clay content is migratory illite, and 15% is migratory kaolinite. Therefore, fines migration exacerbated by this low-permeability rock becomes a potential production and injection problem. A study was conducted involving rock mineralogy and dynamic flow to evaluate factors contributing to potential fines-migration damage within the production and injection interval. Introduction Migration of fines is associated with oil and gas production in sandstones as well as carbonate reservoirs. Fine particles located on the surface of rock grains are affected by adhesion, drag, and electrostatic and gravitational forces. Drag and lifting forces detach the particle, whereas adhesion, electrostatic, and gravitational forces press the particle to the surface. Generally, the main sources of movable fine particles in sandstone reservoirs are kaolinite and illite clays. Kaolinite particles are flat plates usually stacked in the form of booklets. The surface area of clay minerals, for example, typically is large because of their structure and small size and is more reactive and prone to mobilization and migration. Once mobilized, the fine particles are retained by size exclusion if their size exceeds the pore-throat size of the matrix. Fines damage also occurs when several small fine particles reach a larger pore throat at the same time and compete for passage through the throat with the result of bridging and sedimentation. Usually, in the case of gas/water flow, the fines move with the wetting water phase. However, fines movement taking place before water movement has been observed in a number of gas reservoirs. The in-situ mobilization and migration of fines without a mobile wetting phase is primarily caused by hydrodynamic drag that exceeds the critical rate to mobilize the fines. It has long been realized during corefloods that colloidal controlled release of particles leading to fines migration may be caused by salinity change following flow rate that causes the fines to bridge at the pore throat. Generally, a decrease in salinity or an increased rate of salinity change leads to particle mobilization. This decrease in permeability caused by decreasing salt concentration has been found to be nonmonotonic.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189513, “An Experimental Investigation of Formation Damage Induced by Produced-Water Reinjection in Unconsolidated Sands,” by Jalel Ochi and Rezki Oughanem, Total, prepared for the 2018 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 7–9 February. The paper has not been peer reviewed. In recent years, many studies have focused on investigating formation damage caused by produced-water reinjection (PWRI). Nevertheless, many questions about this subject remain unanswered, particularly with respect to the occurrence of this phenomenon in unconsolidated sands. This paper describes a coreflooding program performed with sandpacks at different permeabilities, water qualities, and injection conditions. Introduction The authors performed a complete experimental laboratory study using suspensions containing solid particles, mono-sized oil droplets, or both. Several coreflooding experiments using highly permeable sandpacks were performed over a long duration, during which significant volumes, sometimes reaching 100 L, have been injected. Also, permeability evolution has been monitored along three sections of each sandpack in order to better understand the dynamic of associated formation damage. A schematic of the experimental setup used to carry out the coreflooding experiments is shown in Fig. 1. The suspensions containing solid particles or oil droplets were previously prepared in a 70-L reservoir tank. The tank is made from glass to facilitate suspension stirring and to prevent the aggregation of solid particles within it. The tank’s volume allows an injection over days and nights without interruption. The injection of suspension is ensured by a pump equipped with two low-diameter section pistons to ensure a proper injection of suspension without sedimentation of solid particles. Experimental Results Injection of Emulsions With Only Oil Droplets. In investigating the permeability decline generated by the injection of an emulsion with 100 mg/L of oil and 2-µm mean droplet size, the authors found that the formation damage generated by the deposition of oil droplets took place over the entire length of the sandpack. Also, results showed that oil deposition took place first at the entry section, followed by the second and third sections. The oil-deposition dynamic suggests the propagation as a front. Indeed, the oil droplets deposit along the first section until the permeability decline reaches a minimum. Once the permeability decline is stabilized within the first section, the same phenomenon is reproduced successively in the second and then third sections. These results indicate that the permeability reduction of sandpacks depends on the droplet size rather than on oil concentration even if the kinetics of the permeability decline depend on the oil concentration. For the same mean droplet size of 2 µm, the permeability decreases more slowly for an emulsion of 50 than for 200 mg/L, for example. However, whatever the oil concentration, the final permeability decline stabilizes at the same level of approximately 74% of the virgin permeability (26% of permeability loss).

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 190272, “An Advanced Electrochemical System for EOR Produced-Water Desalination and Reduced Polymer Consumption,” by Ben Sparrow, Adrian Ebsary, Derek Mandel, and Malcolm Man, Saltworks Technologies, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. This paper presents pilot-testing results and economics from a novel electrochemical desalination technology for enhanced oil recovery (EOR) produced water. The pilot objectives were to (1) economically desalt produced water to improve hydrocarbon recovery and lower polymer consumption costs for chemical-flood EOR; (2) inform full-scale plant development with a field pilot; and (3) optimize prefiltration, chemical consumption, and energy use to realize greater than 20% return on investment through reduced polymer consumption. Background and Pilot Summary An electrodialysis-reversal (EDR) system that requires minimal pretreatment with proprietary hydrocarbon antifouling ion-exchange membranes packaged in rugged skids with advanced process controls was used. The EDR plant can (1) desalt EOR produced water from up to 20 000 mg/L total dissolved solids (TDS) down to 500–5000 mg/L for reinjection and (2) reduce polymer requirements to decrease chemical costs in polymer-flood operations. EDR desalts by use of an electric field; dissolved ions in the produced water are moved across ion-exchange membranes, desalting one stream while concentrating a smaller volume discharge. The TDS in the produced water can be desalted to any concentration that provides optimal performance specific to the reservoir. Depending on the presence of scaling ions, the concentrated stream can achieve TDS concentrations of 80,000–150,000 mg/L, or, in the case of offshore operations, the concentrated stream can be eliminated through a novel process. EOR operators may add polymers and other chemicals to increase viscosity of injected water and enable increased oil recovery. Tests completed for this work proved that EOR polymers present in the produced water that returns to surface do not foul or pass through the EDR membranes, instead remaining in the desalted water for reuse. In fact, some polymers are reactivated in the desalted output, with viscosity increasing by almost double during desalination, thereby enabling some recycling of original polymer. More importantly, results proved that lower TDS of the injected water can result in up to 65% polymer cost savings, which is a major contributor to operating costs. Polymer consumption increases with TDS in order to reach a target viscosity goal; therefore, desalting the injected water can result in net savings if desalination costs are lower than the incremental polymer-consumption savings. This work showed a 30–40% rate of return on investment. To test the theory, an offsite pilot was completed in advance to prepare for onsite work. Produced water up to 20 000 mg/L TDS with oil in water present up to 600 ppm were tested. Prefiltration consisted of proprietary media filtration to remove suspended solids to less than 20-µm particle size. No pretreatment for the oil was required. This is because of the resiliency of the antifouling ion-exchange membranes, EDR stack design to prevent plugging, and intelligent cleaning systems that detect and react to remove fouling or partial plugging before irreversible events occur.

Technology Update Wells in the South China Sea are characterized by high depletion and narrow drilling windows which exponentially increase the risk of incurring severe losses. Mud density, sufficient to maintain well control, typically exceeds the fracture gradient of the clastic and coal formations. Therefore, operators face a dilemma in balancing the need for mud weight (MW) to remain below the fracture gradient to avoid losses, while also providing sufficient density to block influxes into the well. The Alpha field, with a water depth of approximately 26 m (85 ft), is located in Sarawak Basin, offshore Malaysia. This area has historically been classified as a “high risk” drilling environment due to clastic deposition and unstable coal formations. A process is described that stabilized troublesome zones and enabled the wells to be drilled with MWs higher than the maximum density predicted by leak-off tests or formation integrity tests. A drilling process stabilized microfractures and mitigated many of the issues associated with wellbore instability. The use of a wellbore “shield” allowed use of a higher mud weight which eliminated well influxes while simultaneously achieving zero mud losses to the formation. Furthermore, the technology delivered additional wellbore strength to weak formations, allowing the drilling operation to be completed as per plan. Accordingly, the operator significantly reduced the challenges associated with lost circulation, stuck pipe, and well instability, thereby facilitating easier logging and delivering a quality, and less costly, producing well. Problem-Solving Process Offset well analysis. To understand the drilling risks and past issues, the team led by Petronas analyzed the root source of stuck pipe in offset wells. The cost of stuck pipe and wellbore instability was valued at $5.7 million for Offset 1. The analysis determined the stuck pipe event occurred at the coal layer with three main contributing factors: Failure in understanding the coal and weak zone structure prior to drilling Insufficient fracture bridging material while drilling the coal Poor drilling and tripping practices across the coal seam layer that resulted in a stuck bottomhole assembly Predrilling geomechanics analysis. Failures in offset wells were studied through geomechanics analysis to identify the minimum MW requirement for weak zones and the coal layer. The challenge: excessive MW will lead to coal destabilization, whereas too-low MW may lead to borehole collapse. Borehole breakouts were predicted using the geomechanical model and the actual MW used during drilling offset wells. Many of the predicted breakouts were related to weak coal layers in the 12¼-in. sections. An internal geomechanical report also indicated that the drilling problems frequently occurred after reaching section total depth and were likely a result of time-dependent failure mechanisms and/or mud-rock interaction.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 28484, “Learnings From the High-Temperature Water-Based-Mud Application in Offshore Sarawak,” by M. Abshar M. Nor, SPE, M. Solehuddin A. Razak, and Lingges Devadass, Petronas, prepared for the 2018 Offshore Technology Conference Asia, Kuala Lumpur, 20–23 March. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. The reservoir section of a gas field offshore Sarawak, Malaysia, consists of two massive pinnacle carbonate structures with heterogeneous porosity and permeability and many vugs and faults. Severe to total loss of circulation was expected along with a high bottomhole temperature (BHT). Considering the high risk of lost circulation, the drilling-fluid strategy involved designing and testing a high-temperature (HT) -tolerant water-based mud (WBM). While the main hole was drilled successfully with the HT WBM, the sidetrack experienced a significant reduction in rate of penetration (ROP). Well Design and Execution Challenges During the design stage, determination of the severity of losses in the carbonate formation was met with high uncertainty. Consequently, a WBM system was selected to drill the 8½-in. reservoir section. A shale formation was predicted to be above the carbonate section, and a 9 5 / 8 -in. casing was planned to be set as close as possible at the top of the carbonate to isolate the shale. With the 9 5 / 8 -in. casing in place, the WBM was to be used to drill the shoe track and the remaining small shale section before entering the carbonate reservoir. The BHT of the reservoir was predicted to be 370°F, which was extrapolated from data from offset wells. In addition, the pore pressure in the reservoir was overpressured approximately 14 lbm/gal because of a gas column in the carbonate. The high BHT coupled with the high mud-weight requirement of up to 14.5 lbm/gal led to the design of an unconventional HT WBM, which was a first for the operator. Special attention also was given to the corrosion risk on the drillstring from expected hydrogen sulfide levels up to 150 ppm and carbon dioxide levels up to 20% in the reservoir. Predrill Laboratory Study Laboratory tests were conducted to address major well challenges and overall performance of the system under extreme borehole temperatures. To ensure the mud system was able to withstand temperatures up to 400°F, a synthetic polymer was introduced to the mud design. Several mud formulations were tested and fine-tuned to achieve well-specific mud specifications for optimal hydraulic capability. Laboratory tests in accordance with American Petroleum Institute Recommended Practice 13B were conducted to evaluate the mud properties with various concentrations of additives. Four samples—Samples A, B, C, and D—were prepared and submitted to the same test procedure to understand the mud rheological behavior upon exposure to the HT environment.