Among the various flow assurance problems that the petroleum industry faces, the deposition of paraffin waxes on to the wall of the pipeline is the most challenging. The challenge arises when the crude oil temperature decreases below the wax appearance temperature (WAT) which leads to the wax crystal in the crude oil to crystallize. An efficient method in remedying paraffin wax deposition is the utilization of chemical inhibitors. However, currently used chemical inhibitors are costly and environmentally harmful if a spillage occurs. Therefore, the use of biodegradable or environmently friendly inhibitors as potential chemical inhibitors are being studied by various researchers. This study investigated oleic acid, poly (ethylene-co-vinyl acetate) (EVA) and triethanolamine (TEA) as inhibitors that perform based on the van der Waals intermolecular interaction between the main wax component molecule eicosane C20H42 using the molecular dynamics simulation (MD) procedure via Material Studio 8.0 software package. In order to analyse the desired structural property which is the Radial Distribution Function (RDF), COMPASS force field was used. The RDF and g(r) function portrayed the functional atoms which aid in inhibiting the agglomeration and crystallization of the wax crystal formation. The presence of a carbonyl oxygen in oleic acid plays a vital role to inhibit the wax formation through the van der Waals interaction between active hydrogen atoms in eicosane molecule. Therefore, the chances of wax inhibition in eicosane is higher by introducing oleic acid as an inhibitor as compared to EVA and TEA. The results were then validated experimentally utilizing a cold finger technique under static condition.

Formation testing has been widely prevalent in the industry for critical information, such as reservoir pressure, gradient analysis, and fluid identification, that aids formation evaluation. This paper focuses on the successful evaluation of low-mobility reservoirs using the 3D radial probe as compared to the conventional probe in a comprehensive study of 60 wells (most of them offshore) across India. One of the major challenges in formation evaluation, fluid flow from any interval is not certain. Prospective zones are encountered that lie in unconsolidated sands where critical drawdown pressure cannot be exceeded because of formation integrity issues or there are zones that have low mobility and thus cannot be tested. Reliable pressure results cannot be obtained from these formations, nor can the fluids in these zones be identified because of poor flow potential. To overcome this major challenge, different probe (tool inlet) configurations are used that increase the flow area and help test tight formations (e.g., the 3D radial probe). In this study, 1754 stations were analyzed across several heterogeneous formation types and multiple operators to verify the diverse applicability of the 3D radial probe. The analysis was conducted in two phases. Formation testing results from the first phase showed that 47% and 68% of the points of interest in 2018 and Q1, Q2 of 2019, respectively, across all wells remained unevaluated with the conventional probe. Even among the points that gave valid results, there were low-mobility points where downhole fluid analysis (DFA) was not possible because of poor flow potential. Upon introducing the 3D radial probe in six wells, the shortfall of the conventional probe was overcome, which ultimately contributed to 35% additional evaluation success in 2018. In a comparison of the performance on the same wells and same formations, 3D radial probe fluid identification success in 2019 was 93% compared to 2% success in conventional probe evaluation in these tight reservoirs. Through this study, the uncertainty of fluid typing in the tight reservoir was resolved. Accurate interval permeability values were determined and were input to well deliverability estimates. The 3D radial probe results also help the drillstem test (DST) design, saving significant well cost because wet intervals are avoided using downhole fluid characterization, which revolutionizes formation testing in tight reservoirs.

Temperature-dependent viscosity is one of critical properties in designing facilities for waxy crude oil production. Several viscosity models have been developed and available in literature. Nevertheless, those models are still insufficient to cover all waxy crude oil produced from various regions. Therefore, this work aims to develop a general viscosity model for Malaysian waxy crude oils. Extensive rheological study was conducted and showed that viscosity behavior below WAT can be best described using Herschel-Buckley model. Multiple correlation and regression analysis were also performed to identify critical physico-chemical properties dictating the viscosity behavior. Based on the finding, a general viscosity model was developed by modifying Herschel-Buckley model and incorporate the critical physico-chemical properties. The general model was compared with widely used viscosity model and other models available in literatures to assess its performance on describing the viscosity behavior. The comparison showed that the general model has lowest average absolute percentage error and hence, it is more superior than the other models. Nevertheless, the model still has limitation in describing viscosity at the transition regime which is between WAT and 5°C below WAT.

Ascorbic acid was used to synthesize crystalline starch nanoparticles (CSNP) for the first time. The CSNP was isolated and the influence of the process variables on the physical properties, recovery yield and crystallinity were studied. Rheology of crystalline starch nanofluid (CSNF) was compared with cassava starch (CS) solution and xanthan. Interfacial tension (IFT) of CSNF was studied at various concentration and temperatures. Influence of concentration, temperature, salinity and their interaction with ultrasound were investigated. Sessile drop contact angle method was used to determine the wettability proficiency of CSNF on an initially oil-wet sandstone core. To justify the finding highlighted above, CSNF and CS solution were applied for EOR purposes at reservoir condition. The approaches were efficient in generating sphere-shaped and elongated nanoparticles (50 nm mean diameter) and higher yield of 39%. Increase in concentration, surface area and temperature of CS and CSNF increased viscosity in comparison to decline in viscosity as the temperature increases for xanthan. Increased concentration, salinity and temperature rise of CSNF decreased IFT and altered the wettability of the sandstone core. CSNF increased the oil recovery by 23% and was effective at high temperature high pressure reservoir conditions. The energy consumption and cost estimation has demonstrated that the methods and polymeric nanofluid are cost-effective than traditional methods and products.

The challenges, experiences, and best practices established from cementing in high-pressure high-temperature (HP/HT) offshore wells in India are discussed along with the design and tailoring per the parameters of each well, real-time operation analysis, post-operation evaluation, and lessons learned from 10 years of experience. Challenges encountered, associated potential risks, and solutions implemented to overcome such challenges in a bid to achieve desired zonal isolation are presented. The obvious presence of high temperature (>400°F) and high pressure (>15,000 psi) as well as a narrow range of fracture gradient and pore pressure created challenges in cement, spacer design and field execution. Another task was to maintain desired rheological hierarchy and fluid compatibility of fluid pumped to achieve the desired displacement efficiencies under these vital well conditions. The introduction of specialty chemicals to develop cement and spacer fluid, which can help maintain downhole properties under these extreme conditions, has been vital to the success of dependable cement barriers in these wells. The wells presented multiple issues during the course of planning, and a few of them had to be sidetracked one or two times. Losses during drilling, gas flow, etc., were commonly encountered in both 12 1/4- and 8 1/2-in. sections. This caused a reexamination of cementing practices, particularly for production sections completed with expandable liner hangers (ELHs). The successful liner operation in these wells encountered an additional challenge—placement of the cement sheath with a higher top of cement in a HP/HT environment. An integrated basis of design was developed to help mitigate challenges and achieve objectives, and it primarily included the following: Successful running-in and placement of an expandable liner system Using specialty chemicals to sustain the downhole extreme environment throughout the life of the well Using computer-aided simulators to achieve excellent zonal isolation across and over the zones of interest An expansive additive was used to enhance hydraulic isolation of the zones of interest because it helps the cement expand in an HP/HT environment and fill any microchannels. A 3D displacement fluid dynamics simulator played an important role in determining efficient placement of cement. This helps pinpoint potential fluid channeling caused by reduced standoff, poor displacement efficiency, or abnormal in-hole geometries. Specialized additives were introduced when designing spacers to modify their parameters to withstand downhole HP/HT conditions, which generated the necessary friction pressure under a low pump rate to achieve rheological hierarchy, and eliminate compatibility problems with all drilling fluids. The successful design and cementation of more than 20 HP/HT wells was executed, including the deepest well in the operator's history throughout the previous 10 years.

Injection of chemicals in enhanced oil recovery (cEOR) such as alkaline (A), surfactant (S), and polymer (P) can increase the oil recovery by changing the properties of the injected fluid to make better interaction with oil in the reservoir. In this work, micellar fluid interactions were studied via microemulsion rheological behavior using naphthenic crude oil and stimulated brine contains ASP. The influence of water cut (WC), temperature, salt concentration, shear, and viscoelastic properties were studied using a chemical cocktail consist of ASP and Naphthenic Acid (NAs) crude oil with a formulated biobased chemical that contained synthesized compound. The rheological properties, when added biobased formulation labeled as surfactant S53 and S57 in the ASP-crude oil system, resulted in a different viscosity — viscous-like behavior of emulsion and microemulsion in varying quantity of synthetic brine and temperature. At a specific volume of brine, both emulsion and microemulsion from S53 and S57 undergo a shear-thinning phenomenon where it behaves like a non-newtonian micellar fluid, as when viscosity decreases with the increase of shear rate. This thixotropy characteristic is suitable to be applied at the injection well in which high shear rate condition requires lower viscosity to assist in injectivity. The fluid when it flows into the reservoir, the viscosity increases sweep residual oil in pore and oil film in pore throats. Overall in this paper will describe the rheology and its microscopic behavior of emulsion and microemulsion generated on the addition of S53 and S57 surfactants in determining the condition of cEOR micellar fluids application.

Complete to intermittent dynamic losses during drilling operations in the Early Permian reservoirs of the Bowen Basin are common because of depleted zones, particularly in the Bandana Coal Measures. The losses encountered while attempting to drill to total depth (TD) result in notable setbacks in time, remediation costs, and zonal isolation integrity. Operators have access to a large portfolio of loss circulation (LC) treatments depending on the loss type, rate, and nature of losses. This paper presents a low-solids, highly thixotropic (LSHT) cement system that can help cure losses without incurring costly nonproductive time (NPT). During the recent Springwater campaign, which consisted of 12 wells targeting the Cattle Creek Coal Measures, three of the wells experienced significant to total losses. A number of conventional lost circulation materials (LCMs), including particulate materials, reticulated foams, and fibers, were unsuccessful in curing the losses. As an alternative to a conventional LC cement plug, an LSHT cement system was deployed. The low-solids content and avoidance of any traditional LCMsenable the LSHT system to be pumped through the bottomhole assembly (BHA), which allows for continued drilling. The LSHT cement system is shear-rate dependent, yielding to thin rheologies on application of shear to easily penetrate into the loss zone. When shear is reduced, the slurry gels rapidly to arrest the rate of flow. Additionally, the quick early compressive strength development at shallow depths allows operations to continue without incurring significant loss of operating hours. The solutions provided were pumped through open-ended pipe in one case and through the BHA with a drilling bit in another; both performed in the same manner without hampering equipment capability. Successful application of the LSHT cement technology helps minimize time lost using conventional cement plugs because the LSHT cement can be pumped through the BHA, saving time associated with tripping in and out of the hole to change the BHA. Additionally, the system's early compressive strength development yields time savings, along with savings in otherwise lost fluids, and achieves drilling efficiencies to help manage drilling operations costs.

The objective of this paper is to share the Operator's first experience in utilizing ilmenite in an offshore HPHT well as part of a low cost well initiative and the value obtained by utilization of such a weighting agent in particular towards lowering ECD. After extensive testing micronized ilmenite was used as the weighting agent for the synthetic based drilling fluid (SBM) for the B1 well. This well was classified as high complexity with a narrow margin window and with predicted maximum bottom hole pressure of 12,013 psi at 3,990 m TVDDF. Extensive laboratory testing was conducted to determine the optimum formulation for a 16 ppg SBM. Part of the methodology in the testing was conducting rheology comparisons between various weighting agents, manganese tetraoxide, barite and micronized ilmenite. The subsequent results were then run through hydraulics simulations to determine the best formulation for optimized hydraulics. Additional testing was conducted to determine the overall stability of the system including conducting static sag tests with a similar duration to the planned wireline logging operation. The primary drivers for using this fluid were to reduce ECD in a narrow margin environment and facilitate the taking of good wireline logs by providing optimum hole conditions without any sag. The micronized ilmenite system successfully achieved a similar rheology to manganese tetraoxide with low PV's of less than 50 cP at 17 ppg and a sag index of less than 0.52. These properties were at an OWR of 80:20. This led to both the successful drilling of the well and completing the required wireline logging with no fluids related NPT or issues related to sag. During logging, the mud was static for 5 days without problems. The mud weight of 17 ppg was the highest density, at that time, at which the micronized ilmenite system had been used.

In 2019, Australia led all Liquified Natural Gas (LNG) exporters in incremental growth ( IGU World LNG report, 2019 ), supported by the start-up of the Wheatstone and Ichthys LNG projects. Production and economic recovery of gas are affected by the association of chemical compounds naturally present at low to trace levels within natural gas such as carbon dioxide, hydrogen sulphide and mercury. These contaminants generate a cascade of costly treatments and waste recovery efforts. If the level of mercury in a produced gas stream is higher than expected, the treatment process in the LNG plant rapidly reaches capacity and may cause shut-down of the facility or rejection of gas supply resulting in significant profitability impacts. There may also be long term consequences that could impact on the decommissioning of industrial infrastructures in the future. High mercury levels in produced gas have been reported in South East Asia and Australia ( Chalkidis et al., 2020 ; Black and Saunders, 2018 ; Zeeshan and Manikandan, 2017 ). However, currently there are no standard method to accurately quantify the presence of mercury in gas in the reservoir. The highly absorbent and multi-speciated nature of mercury makes reliable gas sampling difficult and generally leads to gross under-predictions of quantity. The spatial distribution of mercury within the reservoir means mercury may not appear in the initial production phase and its presence in fluids may vary over the lifetime of the field. Understanding the source, the transport mechanism and the distribution of naturally present contaminants in the subsurface is critical for lowering their impact in industrial activity through avoidance. High mercury levels of about 1000 microgram per cubic meter (µg/Sm 3 ) were reported in reservoir gas samples from a sand unit of the Gorgon gas field in the Northern Carnarvon Basin, Australia ( Chevron Australia, 2014 ). Other gas samples from different depth intervals in the same well delivered readings below 20 µg/Sm 3 . The closest exploration well to GOR-1D (about 2.5 km), North Gorgon-1, has provided abundant core materials that were investigated to detect and understand the distribution of mercury in the rocks. Our research seeks to address some of the significant but remaining geoscientific knowledge gaps on the generation and distribution mechanisms of mercury in rocks, from source to accumulation in the subsurface. In this paper, we provide an assessment of the workflow by examining preliminary analytical results on the detection and quantification of mercury in rocks.

The paper presents a case study of an Operator who successfully drilled two challenging wells through optimization of the drilling fluids. Well A was a HPHT well drilled with mud weight up to 18.6 ppg with overbalanced pressure as high as 6,800 psi – the highest overbalanced pressure experienced by the Operator to date. Well B was required to drill through depleted sand and unstable shale where series of severe loss circulation and wellbore instability issues were experienced in the nearby wells. Due to its HPHT nature, the design of the drilling fluids in Well A was expected to have a total solids content up to 70% by volume. Due to this high solid content, the rheology of the fluids system is inherently high posing an issue related to excessive ECD. To further exacerbate the issue, the extreme differential pressure which was expected to be observed in Well A requires the inclusion of bridging material in the system as part of the mitigation plan to minimize the risk of differential sticking. Conventional bridging material such as calcium carbonate and graphite with concentration between 20 to 40 ppb will further increase the amount of solids in the system. Likewise, in Well B, the Operator also observed that the application of common bridging material in the drilling fluids does not help in addressing the severe losses and wellbores instability issue observed in the offset wells. Almost 60% of the offsets encountered severe loss circulation as high as 6,000 bbl mud loss per well. This paper will share several initiatives by the Operator during the design stage in order to optimize the mud formulation to address the challenges for both of these wells. These include evaluation of various types of bridging material and "a must have" mud testing to assess the performance of the drilling fluids system. Subsequently, the Operator has successfully drilled these wells with no issues related to differential sticking, loss circulation and wellbore instability.

Mesozoic age Golapalli sands are found in the Krishna Godavari Basin, located in the East coast of India. These sands are highly prospective for hydrocarbon exploration and development. They comprise of syn rift sediments, often, exhibiting low permeability. In general, these reservoirs do not flow naturally without hydraulic fracturing. Oil presence in Golapalli sands has already been proven in the basin from the exploratory wells. However, conventional saturation modeling using basic petrophysical logs has proved futile in establishing a definite oil water contact (OWC). This adds further complexity in the reserve evaluation and the hydraulic fracturing design. Moreover, the field is divided into multiple fault blocks with localized OWCs. During the initial appraisal phase, wells that were hydraulically fractured produced oil with high water cut. This prompted re-evaluation of saturation modelling with 3 further appraisal wells. All new wells were selected at different fault blocks within the field and were to be drilled as slim holes of 5-7/8in diameter in reservoir section. Potential intervals with natural fractures were successfully evaluated using advanced sonic data. Zones of interest were selected integrating the fractures network identified with advance sonic measurements and high porosity values obtained from basic neutron-density logs. To constrain inversion resistivity-based saturation modelling, a new workflow was adopted to determine reservoir fluid movements prior to hydraulic fracturing in less than 0.05mD formation. Through this approach, fluid saturations were successfully evaluated using a deterministic downhole fluid identification which helped in reducing saturation uncertainties while demarking the transition zone between oil and water in 0.05mD formation. With known oil zone identified, advanced sonic measurements were used to design effective hydraulic fracture models. A successful hydraulic fracture was initiated with excellent oil production with significantly reduced water cut compared to previous wells. In this paper, a novel workflow will be presented that will help in characterizing fluids in tight sands (permeability less than 0.05mD). This workflow integrates the basic openhole logs and formation testing with conventional resistivity-based saturation modeling to accurately pinpoint the OWC in the tight sands. This workflow has applicability in unconventionally tight reservoirs where there is uncertainty in fluid saturations or fluid contacts. Through this methodology, the propagation of hydraulic fracture into the water zone can be prevented which will greatly help in reducing the water cut in such conditions.

A major operator in Malaysia planned to drill into a 6,000-ft horizontal thin-oil rim. The three-well campaign posed very challenging well deliveries for the operator due to potential losses to faults and karst zones, high uncertainty of reservoir productivity, long horizontal laterals, and openhole completions containing an Autonomous Inflow Control Device (AICD) with a low solids tolerance. An optimized drill-in fluid (DIF) and delayed filter-cake breaker were designed and tested to address the following challenges: reduced filtrate invasion, a targeted filter-cake breaking delay time, and high well production rates. In addition, there was a need for a mitigation strategy for total losses and the resulting impossibility of placing the delayed breaker across the entire reservoir section. A customized NaCl-based 9.2 lb/gal DIF with an optimally sized ground marble bridging package was designed to facilitate filter-cake removal using a compatible delayed acid-release cake breaker. This was achieved through the addition of special additives in the DIF to increase the acid solubility of the filter cake. The DIF also included special additives proven to facilitate liftoff of filter cake at relatively low differential pressure, and for enhanced thermal stability of the polymers used. Testing confirmed that the DIF filter cake was efficiently removed by the breaker within the customized delay time. Corrosion testing of the metallurgy used in the completion equipment demonstrated low corrosion rates at the expected 265°F bottomhole temperature (BHT) by both DIF and breaker systems. Laboratory test results confirmed a high return permeability of 97.5% using the integrated DIF and breaker system. Three wells were drilled in the thin-oil rim reservoir and were completed using this system without losses. A relatively high ROP of 90 to 175 feet per hour without differential sticking issues maximized drilling efficiency and reduced the overall drilling costs. DIF density and properties were controlled through a dump-and-dilute technique. The wells were drilled to TD, and the completions run without incident. After the breaker was spotted, sufficient delay time was achieved with which to remove the wash pipe prior to closing the reservoir isolation valve. Approximately two months after spotting the first breaker, the wells were brought online, and the actual gas/oil production rates of the three wells were 50% above expectation. This paper presents the design and successful application of an integrated DIF/breaker system for drilling and completing three of the most complex extended-reach wells drilled by the operator in Malaysia. The complementary designs of the DIF and breaker system components contributed to the successful drilling and production results of these three challenging wells.

Alpha 1 was recognized as the highest overbalanced well drilled in operator's history. A comprehensively designed superior mud system has enabled the well to be drilled successfully, meeting its objectives of producing shallow and intermediate intervals and able to appraise deeper 8-1/2" HPHT section. The HPHT section exhibits a marked pressure spike to pore pressure up to about 14,000psi with 310°F bottom hole temperature. The formation prognoses are very much uncertain due to limited data available from offsets. This considerable HPHT drilling challenges are further compounded by the high overbalance pressure - approximately 6,800psi observed while drilling with 18.4ppg mud weight. Drilling mud designed for high overbalanced pressure well requires special attention particularly on the HPHT filtration control and mud rheology. In deeper section where wellbore pressure control is critical with approximately 1.5ppg drilling margin, the mud formulation and rheology was optimized in minimizing ECD. The components of the mud were heavily scrutinized to minimize risk of wellbore losses and differential sticking. Low fluid invasion system was introduced to provide wellbore shielding mechanics. Operator has made initiatives of conducting unconventional laboratory works in assuring the technical performance. Cost reduction initiative was also made by optimizing mud design with surplus mud and chemical inventory. These were incorporated into the mud design as to have low cost and fit for purpose mud formulation. In actual operation, the mud rheology and ECD were deviated from the plan. Both major deviations demanded several adjustments on the mud formulation. Several lab tests were conducted and unconventional mud apparatus were brought offshore for further fine tuning on mud formulation. The 8-1/2" HPHT hole section was successfully drilled with no issue pertaining to losses, drag during tripping and differential sticking. The best practices and lessons learnt replicated from few HPHT wells drilled previously, in combination with the close collaboration on laboratory works with contractors has contributed greatly to the success of the well.

Downhole fluid analysis (DFA) has proved to be an effective technology for assisting in understanding reservoir dynamics, fluid distribution, reservoir compartmentalization and in-reservoir processes. Until recently, DFA technology was only available with wireline-conveyed tools. It was typically performed after the well had been drilled, limiting the ability for real-time decision making. The recent advent of logging-while-drilling (LWD) DFA technology — also known as fluid mapping-while-drilling (FMWD) — allows operators to make informed and timely decisions early on well construction, landing, geosteering and completion without pulling out of hole. This paper presents the results of an FMWD campaign by Repsol in Malaysia. FMWD technology was deployed in five wells with different objectives but with the common goal of enabling real-time decision making prior to the bottomhole assembly (BHA) reaching the surface. The FMWD objectives were to assess reservoir connectivity, monitor pressure depletion, measure CO 2 content, and differentiate between formation fluids (gas, oil, and water). For exploratory targets, the service was run to confirm the presence of hydrocarbons and to assess in-situ fluid properties. In a highly deviated well, the technology was used to confirm fluid properties for geosteering the wellbore through a targeted zone if it proved to be oil bearing. The campaign was very successful, and the objectives were fully achieved. With the completion of more than 130 pressure tests, a comprehensive and complete pressure profile was obtained in each of the five wells, allowing for the selection of the most appropriate depths for DFA fluid scanning and sampling. Twenty-four DFA stations enabled clearly identifying fluid types in various exploratory and appraisal targets. This information was then used to make key decisions on well landing and completion strategy. In addition, CO 2 was systematically identified and quantified by the tool optical spectrometers; thereby, accurately mapping its distribution across the field. Real-time data transmission using mud pulse telemetry allowed for real-time monitoring and important operational decision making. In some cases, only 15 minutes of pumpout was sufficient time to identify the movable reservoir fluid phase. In other cases, physical downhole fluid samples were collected once the mud filtrate contamination had sufficiently decreased below the predefined acceptable limit. In general, the time on each station was brief, which was attributed to reduced depth of filtrate invasion because FMWD operations took place soon after drilling. This paper presents the lessons learned from introducing of the FMWD service in exploration, reservoir management and geosteering, within the same five-well drilling campaign. Until the present time, this technology was only available using wireline. However, the introduction of LWD DFA has been found to be disruptive for reservoir management, drilling, completion, and geosteering applications, similar to the way formation pressure-while-drilling (FPWD) was a gamer changer for the drilling industry when introduced in early 2000s.

Guar gum and its derivatives based fracturing fluids are most commonly used in hydraulic fracturing. For high temperature wells, guar-based fracturing fluids need to be formulated with higher polymer loading and at a high pH that leaves insoluble residue and tendency to form scales with divalent ions. In this paper, a systematic approach to field deploy a novel low-polymer loading, nondamaging acrylamide basedfracturing fluid system is presented. Thermally stable acrylamide-based polymer with reduced polymer loading of 30-40% less than guar-based fracturing fluid was considered to minimize formation damage concerns. For successful field deployment, a novel nondamaging fracturing fluid was evaluated in following sequence: chemical management and quality control, optimization of fracturing fluid formulations with field water, field mixing procedure, onsite QA/QC, friction analysis, leakoff analysis, data frac analysis and execution of main fracturing treatment. In both scenarios, batch mixing and on-the-fly mixing of linear gel were evaluated. The friction of crosslinked fluid was analyzed by using bottomhole gauge and fluid efficiency was evaluated during data frac analysis. This paper presents rheological studies at bottomhole static temperature (BHST) and cool down temperatures of selected well candidates that demonstrate superior thermal stability of this novel fracturing fluid. With polymer loading of 25 lb/1000 gal, the fluid viscosity stayed above 300 cP at 100 1/s shear rate for 2 hours at 290°F. The fracturing fluid formulations were optimized using both live and encapsulated breakers with high pressure and high temperature (HPHT) rheometer. Due to the fast hydration of the base polymer, the linear gel was mixed both in batches and on-the-flying during the main fracturing treatment. Slightly higher friction at higher pumping rate was observed by the down hole gauge during data frac for this novel fracturing fluid as compared to guar-based fracturing fluid. The main fracturing treatment was successfully executed with 45-50 barrels per minute (bbl/min) pumping rate with increased proppant concentration up to 5 pounds per gallon (ppa) using 30/50 high strength proppant (HSP) proppant. The fracturing fluid system based on the novel acrylamide copolymer offers advantages over guar-based fracturing fluid such as low polymer loading, excellent high temperature stability and less formation damage. This paper presents a systematic approach and lesson learnt during novel fracturing fluid deployment.

Surge and swab pressure generated during pipe tripping operations tends to result in various wellbore stability and integrity problems. To monitor these problems, prediction of these differential pressure is required for the smooth functioning of drilling operations. An analytical predictive model is presented in this research for surge and swab pressure. This model is developed under steady-state condition for Yield Power Law fluid. A fluid filled wellbore with drill-pipe/casing is considered as two concentric cylindrical pipes for developing this model. In this concentrical cylinder inner pipe is moving at certain velocity and the outer pipe is stationary. Due to movement of inner pipe, drilling fluid will start displacing in annulus and results in pressure surges. A predictive model is developed by analytically combining the frictional pressure loss and mud clinging effect to forecast this pressure surge due to couette fluid flow phenomena in wellbore. The newly developed model (NDM) is validated with two existing analytical models and reported experimental data that are available in the published literature. A parametric analysis is carried out to identify the effect of various parameters on pressure differential. This research suggests that with the increase in pipe tripping velocity, surge pressure also tends to increase because of high viscous drag of fluid. It is also found that the increase in diameter ratio surge pressure also tends to increase due to large shearing effect between pipe wall and fluid. In conclusion this model is predicting the suitable range of tripping speed and diameter ratio under tolerable wellbore pore and fracture pressure to assure downhole wellbeing. Unlike most of the existing model, NDM requires less numerical analysis which make it easier to understand and apply in real case situation. The model considers mud clinging effect for precise prediction of surge/swab pressure gradient.

This research studies the potential of microwave irradiated plantain peels starch as additive to minimize the filtrate in water-based drilling fluids. The fact of agro-waste rapid growth has become centre of this research. Also, problem induced by filtration loss into the formation encourages research in this study. The formulation for the mud were prepared by using the standard mixture and added with different concentration of plantain peel starch. The novelty of this study is the investigation on the effect of microwave treatment on the properties of plantain peels starch which affects the performance of the drilling fluid. The influence of the non-ionizing microwave effect on starch changed the physical and chemical properties by the disintegrated intermolecular bonding of the starch particles. Microwave heating reduced the moisture content of the starch by 81% due to rapid heat transfer within the starch granule. The water binding capacity of the starch has increased by 42.4% as compared to the non-microwaved starch. The swelling power curve increased to the factor of 3 and as temperature reaching 80?C the factor reduced to 1.5. Solubility curve of microwaved starch is on the other hand lays below the non-microwaved curve shows that microwave irradiation decreased the solubility of the starch. Next, the performance of mud is evaluated with the presence of different concentration of native and microwave irradiated starch. Plantain peel starch did not affect the mud weight. The starch additives did not alter the pH and the mud pH is in the accepted alkali range. The starch concentration is directly affecting the viscosity of the mud. The presence of the starch in the mud enhanced the viscosity of the mud and also the yield point which favours the drilling operation as yield point indicates the ability of mud to transport cutting to the surface. Simultaneously, gel strength of the mud also improved with the presence of plantain peel starch and further enhanced with the presence of microwaved irradiated starch. In addition, plantain peel starch improved the fluid loss volume and further ameliorated the fluid loss when the microwave-treated starch added in the mixtures.

Qiongdongnan Basin has deep water and narrow pressure window in South China Sea. In the process of drilling, it is often accompanied by complicated conditions, such as gas invasion, well leakage and breath effect during drilling. Therefore, we have carried out long-term research and practice. According to SPP, dc index, drilling fluid displacement and density and so on, we established a real-time gas invasion early warning neural network model. We formed multi factor measures to prevent lost circulation during drilling. We have drilled more than 20 deep-water narrow pressure wells, and the success rate of drilling reached 100%. Key words: Ultra-deepwater drilling; Narrow pressure window; Gas invasion; Well leakage; Breathing effect

Wax deposition is a serious issue during the pipeline transportation of crude oil. This research work has investigated the effects of some important parameters on the flow characteristic of crude oil during the pipeline transportation in offshore and onshore field environments.i.e. effects of thermal/shear conditioning and aging on the flow properties of virgin crude oil and additive-treated crude oil. Polymeric nanocomposites are a new and improved family of pour point depressants that can enhance the performance of polymeric additives. This work is in continuation of our previous work of Sharma et al. 2019c , where polymeric nanocomposites based on graphene oxide were synthesized, namely poly (methyl methacrylate)-graphene oxide [PMMA-GO] with different concentrations of graphene oxide (0.5, 1 wt. %), and were subsequently evaluated as potential pour point depressants for a waxy Indian crude oil possessing substantial wax deposition and gelation issues. The effectiveness of the PMMA-GO was examined in this work based on its pour point depression, flow performance, and enduring thermal conditioning, shear conditioning and aging phenomenon in the PMMA-GO treated crude oil. Its performance was compared to that of polymer PMMA-treated crude oil, and a PPD-wax interaction mechanism was proposed. The effects of thermal conditioning on the performance of PPDs were evaluated by determining the gelation points at cooling rates of 0.5, 1 and 1.5°C/min. Also, the pour points of additive-treated crude samples were calculated after repetitive heating at temperatures 60°C, 55°C, 50°C and 45°C. The effects of aging on the flow behaviour of crude oil were determined by obtaining the rheological properties and pour point values on the 1 st and 15 th day of its storage. For evaluation under shear conditioning, apparent viscosities were measured over shear rates of 0.1-500 s -1 at temperatures 30°C, 40°C and 50°C below and near wax appearance temperature (WAT). This study complements the benefits of the PMMA-GO as a flow improver obtained in our previous study and details its effectiveness under more practical applications.

Drilling wells in mature fields normally entails the integration of multidisciplinary teams to increase the likelihood of a successful drilling and completion program. Maximizing wellbore productivity requires thoughtful planning involving analysis, studies, and risk assessment of the best alternative solutions for well drilling and completion. Selecting reservoir drilling and completion fluid to minimize rock formation damage requires a high level of consideration. Selecting an appropriate fluid strategy becomes more significant when the reservoir section involves horizontal drilling and an openhole completion design. This paper details the design criteria and final application of a nondamaging drill-in fluid to drill a horizontal well completed as open hole in a mature field (first of its kind in the field). The fluid design strategy was driven based on analysis of reservoir rock samples, reservoir fluid chemistry analysis, and the natural permeability of selected core samples. The fluid selected was a monovalent brine system using highly clarified and acid-soluble biopolymers as filtrate reducer and viscosity control, respectively, and an engineered and tested bridging package based on sized calcium carbonate. The fluid also contained an amphoteric amine to control clay swelling and dispersion. The nature of the well completion used an in-situ acid-generating filter-cake breaker system for removal of filter cake and damage encountered during reservoir drilling or completion. The filter-cake breaker system also affected fluid design (e.g., compatibility between the two systems), which was incorporated into the design strategy. Additionally, the nature of certain details of the completion architecture affected the breaker system application and was necessary to redesign the filter-cake breaker system to achieve optimal wellbore cleanup while accommodating constraints in the completion design and operation. Finally, application of the fluid program used with the drilling and completion design and architecture rendered a successful project resulting in higher than expected hydrocarbon output.