Abstract Most 5 1/2in-casing mature wells need to be re-fractured for improving the ultimate recovery. Over the last decade, operators focused on the sidetracking well completion for maximizing wellbore contact. Acid fracturing tend to be performed to treat the reservoirs and make fractures system more complicated as much as possible. The irregularity of slim hole has negative influence on the deploying of completion or fracturing assembly. Isolation tools are usually subjected to heavy corrosion caused by acid or proppant fluid. The 3 1/2in Open-hole packer-sleeve (OHPS) completion assembly including improved external casing packer (ECP) were proposed for sidetracking well completion. The water-swellable packers (WSPs) with anti-corrosive thermo-plastic vulcanizates (TPVs) was used as the alternative to current mechanical-set ECPs. The TPV matrix was prepared by physically blending high-strengthen carboxylated nitrile (XNBR) with polyamide (PA6). To improve the swelling performance, newly-developed Porous Super Absorbent Resin (PSAR) was mixed and distributed into XNBR/PA6 system. The new swellable TPV exhibits the advantages of high strength, anti-corrosive property and high reliability over traditional packing materials. The TPV material characterization and annular sealing test of 3 1/2in prototype was conducted in the lab. One 5 1/2in mature oil well was selected for field validation. One 3 1/2in OHPS string with four stages was successfully tripped into large-deviated slim borehole. During the stimulating operation, WSPs acted as effective barriers and any communications between stages did not occurred. It is concluded that the new OHPS using improved WSPs meet requirements of slim-hole sidetracking well completion and stimulation.

Abstract This paper develops a novel WFS model for transient pressure analysis in multi-stage fractured horizontal wells. In the WFS model, two concepts called WFS pressure and WFS index are introduced and an additional skin factor in the interface of inner and outer regions is applied based on a radial composite reservoir. Then, a novel multi-stage fractured horizontal well model is developed by considering the WFS, stress-sensitivity effects, and finite-conductivity fractures. The reservoir model is solved by the perturbation transformation, Laplace transform, and numerical inversion. While the fracture model is solved by fracture discretization and superposition principle. Finally, the bottom hole pressure is obtained. Following that, model verification and sensitivity study are performed. It is found that the flow regimes of the WFS model includes bilinear flow, linear flow, first radial flow, bi-radial flow, pseudo radial flow, and WFS flow. An interesting feature of "hump" caused by WFS flow exhibits in the pressure derivative curve. The results of sensitivity study show that the height of that "hump" increases as the WFS pressure increases, but is independent of WFS index. What’s more, WFS flow exhibits a closed boundary flow when the WFS index is equal to zero, while it appears as a constant pressure boundary flow when WFS pressure is very tiny. Through the WFS model, the fluid supply characteristics of tight gas reservoirs are fully understood.

Abstract The study of pressure transient behavior in fractured-vuggy reservoirs has recently received considerable attention because a number of such reservoirs have been found worldwide with significant oil and gas production and reserves. In recent years, the use of highly deviated wells (HDW) is considered an effective means for developing this type of gas reservoir. However, in many fractured-vuggy reservoirs unexpected high gas production have been observed which cannot be identified with pressure transient models of horizontal well with pseudo state triple-porosity interporosity flow. This paper presents a semi-analytical model that analyzed the pressure transient behavior of HDW in triple-porosity continuum medium which consist of fractures, vugs and matrix. Introducing pseudo-pressure, Laplace transformation and Fourier transformation were employed to establish a point source and line source pseudo-pressure solutions in Laplace space. Then the pseudo-pressure transient curve was got by numerical inversion. Furthermore, the flow characteristics were analyzed thoroughly by examining the curve which is mainly affected by inclination angle of HDW and interporosity flow coefficients between different pore media. Sensitivity analysis on the pressure transient behavior was performed by varying some important parameters such as the inclination angle, fracture storativity ratio and interporosity flow coefficients. Finally, a field case was successfully used to show the application of the presented semi-analytical model. With its high efficiency, this approach will serve as a reliable tool to evaluate the pressure behavior of HDW in fractured-vuggy carbonate gas reservoirs.

Abstract Currently, most of offshore platforms are equipped with gas turbines to fulfill their power requirement and consequently produce CO 2 emissions as a by-product. The energy efficiency of the asset is a key factor in reducing their carbon footprint impact. Numerous ways can be considered within the process and utility systems to improve the energy balance. This paper will investigate the possibility to exploit the available hydraulic energy onboard offshore platforms to transform it into electrical energy. Part of the recoverable hydraulic energy is found in pressurized pipes where the flow is in charge or in other words under hydraulic pressure. The aim is to develop a novel turbine that will be optimized for water disposal energy recovery on offshore platforms. Hence the objective is to install a turbine to replace a conventional valve to maintain and regulate the pressure as well as generating electricity. In close collaboration with TechnipFMC, ICube laboratory (Strasbourg, France) is completing a development program for such an hydraulic turbine. This paper describes some outcomes of this comprehensive study performed by experimental engineers and researchers in the hydraulic discipline with the support of engineering integration by TechnipFMC.

Abstract 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.

Abstract The fracture pressure in the reservoir is a function of reservoir pressure. Reservoir depletion will reduce the magnitude of reservoir pressure and consequently the reservoir fracture pressure. The fracture pressure changes because of reservoir depletion can lead to challenges like closure of mud weight window. Hence, the ability of predicting the fracture pressure changes due to reservoir depletion is a key for field development including infill drilling campaign. A reasonable amount of field data has been published across the oil and gas industry to understand fracture pressure reduction as a function of reservoir depletion. The data show approximately a linear relationship between the reduction of fracture pressure with reducing reservoir pressure. Several studies and laboratory measurements have also been made to assess the impact of the reservoir depletion on the fracture pressure. Almost all the studies and laboratory measurements show reduction of fracture pressure as a function of reservoir depletion. In this study, we present several field examples showing that severe reservoir depletion has little to no impact on the fracture pressure and consequently on the mud weight window. The examples show that heavily depleted reservoirs were drilled with high over balanced mud weight without seeing any sign of loss events. These observations are not fully aligned with what has been observed in the published field data.

This paper develops a novel WFS model for transient pressure analysis in multi-stage fractured horizontal wells. In the WFS model, two concepts called WFS pressure and WFS index are introduced and an additional skin factor in the interface of inner and outer regions is applied based on a radial composite reservoir. Then, a novel multi-stage fractured horizontal well model is developed by considering the WFS, stress-sensitivity effects, and finite-conductivity fractures. The reservoir model is solved by the perturbation transformation, Laplace transform, and numerical inversion. While the fracture model is solved by fracture discretization and superposition principle. Finally, the bottom hole pressure is obtained. Following that, model verification and sensitivity study are performed. It is found that the flow regimes of the WFS model includes bilinear flow, linear flow, first radial flow, bi-radial flow, pseudo radial flow, and WFS flow. An interesting feature of "hump" caused by WFS flow exhibits in the pressure derivative curve. The results of sensitivity study show that the height of that "hump" increases as the WFS pressure increases, but is independent of WFS index. What’s more, WFS flow exhibits a closed boundary flow when the WFS index is equal to zero, while it appears as a constant pressure boundary flow when WFS pressure is very tiny. Through the WFS model, the fluid supply characteristics of tight gas reservoirs are fully understood.

Currently, most of offshore platforms are equipped with gas turbines to fulfill their power requirement and consequently produce CO 2 emissions as a by-product. The energy efficiency of the asset is a key factor in reducing their carbon footprint impact. Numerous ways can be considered within the process and utility systems to improve the energy balance. This paper will investigate the possibility to exploit the available hydraulic energy onboard offshore platforms to transform it into electrical energy. Part of the recoverable hydraulic energy is found in pressurized pipes where the flow is in charge or in other words under hydraulic pressure. The aim is to develop a novel turbine that will be optimized for water disposal energy recovery on offshore platforms. Hence the objective is to install a turbine to replace a conventional valve to maintain and regulate the pressure as well as generating electricity. In close collaboration with TechnipFMC, ICube laboratory (Strasbourg, France) is completing a development program for such an hydraulic turbine. This paper describes some outcomes of this comprehensive study performed by experimental engineers and researchers in the hydraulic discipline with the support of engineering integration by TechnipFMC.

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.

The fracture pressure in the reservoir is a function of reservoir pressure. Reservoir depletion will reduce the magnitude of reservoir pressure and consequently the reservoir fracture pressure. The fracture pressure changes because of reservoir depletion can lead to challenges like closure of mud weight window. Hence, the ability of predicting the fracture pressure changes due to reservoir depletion is a key for field development including infill drilling campaign. A reasonable amount of field data has been published across the oil and gas industry to understand fracture pressure reduction as a function of reservoir depletion. The data show approximately a linear relationship between the reduction of fracture pressure with reducing reservoir pressure. Several studies and laboratory measurements have also been made to assess the impact of the reservoir depletion on the fracture pressure. Almost all the studies and laboratory measurements show reduction of fracture pressure as a function of reservoir depletion. In this study, we present several field examples showing that severe reservoir depletion has little to no impact on the fracture pressure and consequently on the mud weight window. The examples show that heavily depleted reservoirs were drilled with high over balanced mud weight without seeing any sign of loss events. These observations are not fully aligned with what has been observed in the published field data.

Fractures Robots (FracBots) are underground IoT (internet of things) wireless sensor nodes designed to be deployed in oil/gas reservoirs to map hydraulic fractures (HF) and monitor in real-time main reservoir parameters including pressure and temperature in real-time. A significant amount of FracBots will be injected inside hydraulic fractures immediately after conducting the fracturing job to gain the required data. They will launch the network connectivity in a fashion of FracBot-to-FracBot to collect, exchange data and transmit it to the base station installed in the wellbore. FracBots technology employs the same concept of the wireless underground sensor network (WUSN), a very capable technology for the applications in hydraulic fractures network. However, developing such technology is exceptionally challenging due to many environmental complications. The main challenges are severe environment, size, and energy limitations which contribute heavily to destroying the quality of the underground wireless communication link. FracBots technology comprises a gateway, a base station (BS), and FracBots. The main role of the BS is to transfer power to FracBots for charging purpose, gather data from FracBots, and finally transmit data to a gateway that send them to a centralized computer for further processing. The function of FracBot nodes is to sense the required data, send it wirelessly among them in multi-hop fashion and then communicate data to BS. This paper discusses the available wireless communication techniques including electromagnetic waves (EM) and magnetic induction (MI) wireless communication that might be suitable candidates for hydraulic fractures environment. They are compared in terms of the path loss model, path loss parameters, and the advantages and disadvantages of each technique. Moreover, we provide several simulations showing the importance of omnidirectional antenna and the effect of an alignment angle (between the axes of transmitter and receiver) on the path loss of the MI network. Also, we analyze the environmental effects on the path loss inside hydraulic fractures. After studying both EM and MI techniques in fractures environment. We found that the heterogenous environment stiffly influences the EM and MI communications inside hydraulic fractures in oil reservoirs. A hybrid solution that combines both EM and MI communication technologies will be very suitable for such an environment.

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.

It is today an undoubted fact that the role of gas condensate systems has increased multifold in the global energy chain. However, the development and production of gas condensate systems remains a challenge to the petroleum industry due to its technical complexity. The production data analysis methodologies that has been followed throughout the industry to estimate gas condensate reservoir performance are conventional technologies which have proved ineffective in forecasting and estimating the gas condensate reservoir performance. The complexities involved in the gas condensate system like liquid dropout, condensate blockage and successive multiphase flow of gas and condensate along with the extensive early-transient infinite acting behavior are the root cause for the failure of the gas condensate system.The similarity method transforms the governing PDE for fluid flow into ODE written in terms of single independent variable that combines time and space. The similarity method provides a unique advantage of solving the obtained ODE without the need for linearization. In this paper, the Boltzmann transformation technique is applied to governing equations for multiphase flow for two inner boundary conditions (constant gas flow rate and constant bottomhole pressure) in linear and radial flow regimes. The proposed model is validated by using the line-source solution for single phase gas flow above the dewpoint. The proposed analytical solution for flow above the dewpoint pressure reasonably coincided with the line-source solution for flow above the dewpoint, thus, the proposed methodology can be used as an alternative and less time-consuming approach to predict reservoir performance in early transient multiphase linear and radial flow gas condensate systems. The capillary pressure effects considered in the paper were reasonably negligible considering the fact that a negligible capillary difference was used in fluid PVT properties. But was significant when incorporated as an additional pressure gradient term. This however, demonstrated that capillary pressure effects play a vital role in the production data analysis in gas condensate reservoirs. There is no analytical production analysis method developed to date has considered pressure-saturation as a function of a non-dependent dimensionless coordinate in multiphase (oil, gas and water) linear and radial flow systems. This paper aims to fill this knowledge gap by extending a modification of the similarity method to fully incorporate capillary pressure effect in multiphase linear and radial flow systems in which pressure and saturation are simultaneously considered as functions of a dimensionless coordinate.

In the shale oil reservoirs, the horizontal wells with large-scale fracturing treatments have been the most effective tools to enhance oil productivity. After large-scale fracturing treatments, many micro-seismic data showed that the fracture networks are generated in the reservoir along the wellbore. Understanding the complex fracture properties is the primary step for fracturing evaluation and productivity estimation. Thus, an efficient approach is needed to estimate the fracture properties. To improve this situation, a well-testing approach was proposed in this work to identify the fracture properties. This work was organized as follows: (1) developing a well-testing model of multiple fracture horizontal well (MFHW) including reservoir flow equations, fracture flow equations, and mass balance equations, (2) solving and verifying the proposed model using boundary element method, superposition principle, and numerical approach, (3) applying the well-testing model to investigate the pressure transient behaviors, and (4) estimating the fracture properties of shale oil wells from the Junggar Basin.

Slickwater fracturing has increased over the past couple of decades in the development of shale and tight formations. Friction reducer is the main component of slickwater, which reduces drag in the tubular. For successful and economical slickwater hybrid fracturing treatment, selection and optimization of friction reducers play a key role. This paper presents a new insight into optimizing friction reducer using helical coiled flow loop at high-pressure, high-temperature (HPHT) conditions. Usually, friction pressure is estimated by pumping slickwater fracturing fluid through a straight tube and measuring differential pressure across the tube. This required pilot-scale laboratory setup and testing at HPHT bit challenging. In this paper, small sized equipment, helical coiled flow loop was utilized to estimate friction pressure of slickwater fracturing fluid. Friction reducers can be rigorously tested for degradation because secondary flow resulting from centrifugal forces can be caused by the coil curvature. Correlations for Darcy friction factor as a function of Reynolds number has been developed for helical coiled fluid loop in both laminar and turbulent flow regime. The present study evaluates different friction reducers in ¼ in. ID smooth helical coiled flow loop. The correlations developed for Darcy friction factor was well validated for water with data available from literature. Polyacrylamide based friction reducers with different concentration were used in this study. The friction pressure, with and without friction reducers, was compared at different flow rates. Percent drag reduction at different polymer concentration was also evalauted using helical coild flow loop. Thermal degradation of friction reducers was evaluated by varying temperature up to 300°F. New correlations to measure friction losses using helical coiled flow regimes are presented in this paper. Reduced drag reduction due to secondary flow resulting from centrifugal forces in helical coil can judge friction reducer more thoroughly then conventionally used straight tube flow loop.

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.

In a typical waterflooding philosophy, water injection is often constrained by the in-situ stress of the overlying geological seal, in order to avoid out-of-zone injection and ensure reservoir fluid containment. Direct measurement of in-situ stress from wireline Micro-frac testing is insightful as compared to a conventional leak-off test (LOT) conducted at the casing shoe, due to the smaller volume and lower injection rate used. Unlike the conventional LOT, Micro-frac tests can be performed at discrete and multiple intervals in one wireline run, away from the casing shoe. In 2017, Shell Malaysia Exploration and Production (SMEP) conducted the first wireline Micro-frac test in a caprock shale, in a deepwater injector well, offshore Malaysia. The job was successfully executed with an improved design of the flowback mechanism, using a combination of a small volume pump and a drawdown chamber. While the small volume pump provided the advantage of accurate volume/rate measurement, the modified drawdown chamber setup provided a constant flow rate, to aid in a more accurate fracture closure pressure interpretation. The improved setup was the first successful application of this device for the purpose of Micro-frac. Both the methodologies showed good and comparable results, thereby adding higher confidence to the interpretation of fracture closure pressure. A workflow has been developed to ensure successful execution of the logging job. Pre-job modeling was completed using offset well data to derive formation mechanical properties as well as in-situ stress profile. This information was then used to characterize formation breakdown pressure, selection of test intervals and optimum straddle packer positioning. Learnings from the test conducted at the first depth station were used to optimize the number of cycles for the subsequent stations. In addition, an operational decision tree was developed to assess the number of cycles required and contingency criteria. The paper presents an improved flowback design using the drawdown chamber as well as the operational challenges in a deepwater environment. The methodology provided a reliable estimate of fracture closure pressure in a non-permeable formation. Results have been used to update the water injection envelope, in an effort to avoid undesired out-of-zone injection.

The main objective of this study is to map potential fracture density based on a new integrated study of a fractured basement area. A machine learning algorithm of well log fracture density - borehole image log (BHI) guided seismic inversion was performed. Structural seismic attributes which are including maximum and minimum curvature, coherence, ant tracking, neural network, and principal component analysis were used to validate this potential fracture density map. All fractures were interpreted after image from BHI was processed. These fractures were quantified as fracture density log (FDL) based on weight density fractures per meter. The inversion was performed based on the enhanced of Extended Elastic Impedance (EEI) with the FDL. It was done by defining the training data set relating the FDL and its associate EEI. The resolution of inversion is increased by conducting stochastic inversion to generate high frequency relative EEI. The absolute value EEI was obtained by adding the relative EEI with a low frequency model derived from the FDL. A study was conducted in the Field A of the Malay Basin, which is located in transtensional tectonic regimes with the domination of various rock types ranges from metasedimentary rocks to volcanic and igneous rock. The integrated study has been implemented to invert the potential fracture density of the fractured basement area. Based on the BHI analysis, the highest fracture density is defined as 1.3 fractures per meter. Inversion at the well location shows a high correlation and small error of the reconstructed fracture density (FDL). The analysis of cross section and the horizontal slice of inverted fracture density displays good fit with a fracture sensitive analysis, which is structural seismic attributes such as minimum and maximum curvature, coherence, ant tracking, principal component analysis, and neural network. This study provides a better fracture understanding as the resulted inverted fracture density is quantitative. It allows potential fracture density mapping by using geobody analysis through classification or cut off value. The novelty of the study is presented based on the potential to generate a 3D volume of well log calibrated fracture density by empowering the seismic elastic inversion with a sophisticated machine learning algorithm.

Formation sand production is a major concern in brown field operations, especially as the field depletes and water production commences. There are many methods to control sand production in primary well completion; however, it becomes more challenging in producers where no primary sand control is installed initially, and it starts producing sand later in the well life. Selecting the right method for remediating these wells has become a hot topic with both Operators and Service Providers alike striving to discover effective and economical solutions for their brown-field operations. Currently, the solutions for through-tubing sand control in existing producers are screen hang-offs, through-tubing gravel packing 1 (TTGP) and chemical sand consolidation. Through-tubing sand screen (TTSS) hang-offs above the producing zone, is an inexpensive sand control method. Unfortunately, these installations are typically short lived, often requiring regular well interventions due to screen plugging or erosion, or sand clean-out operations to remove sand accumulated in the production tubing. Alternatively, TTGP is a robust method to control sand production; however, more equipment is required to deploy the gravel pack which subsequently increases costs significantly in offshore applications. To simplify TTGP and make it economical, a major Interventions Service Provider devised a methodology to install TTGPs utilizing Slickine that reduces the overall installation cost tremendously. The methodology has been proven a great success in the US Gulf of Mexico where over 1,200 applications have been installed. The pilot implementation of slickline deployed through-tubing gravel pack (SL-TTGP) was executed in three S-Field wells in late 2018 which were shut-in due to higher than permissible sand production. These were challenging intervals in that they were uphole recompletions between cement packers in dual string 9-5/8" casing which had produced sand. The results from the installation proved that the methodology provides effective sand control and enables reinstatement of production from these wells. Further, the installations were achieved with lesser resources and at lower costs; less than half that of a CTU deployed TTGP. This success has led to further installations in the following year. This paper presents in detail the case study of the pilot implementation of SL-TTGP, key successes, as well as critical lessons learnt during execution and production phase. It includes the challenges, risks and their recommended mitigation plans, as well as the well performance comparison before and after the implementation both in terms of production and sand count.

Borate crosslinkers are the most commonly used crosslinker in fracturing fluids. However, they exhibit lower performance at high temperature, high pressure, high water salinity, and low pH applications. Consequently, zirconium crosslinkers are utilized to address these limitations. Zirconium crosslinking chemistry is complex and depends on many factors such as pH, metal to ligand ratio, ligand order, ionic strength, and type of polymer used, which in turn influence the delay time, thermal stability and shear resistance performance. This work evaluates the rheological performance of four different zirconium crosslinkers with a biopolymer and a synthetic polymer. The tested crosslinkers are manufactured in different chemical structures. The two polymers tested are 40 lb/1,000 gal CMHPG and 40 lb/1,000 gal synthetic polymer. The rheological performance was measured through HPHT rheometer (100 s −1 shear rate) at 200-400°F for 2 hours. The shear tolerance performance was also evaluated under a custom shear rate schedule (100-1000 s −1 ). The results show significant variation in crosslinking performance due to the changes in crosslinker chemical structure and type of polymer used. Zirconium lactate and propylene glycol crosslinker shows the highest enhancement in shear and thermal stability with CMHPG based fracturing fluids. Surprisingly, the same crosslinker performed the least with synthetic polymer-based fracturing fluids. However, Zirconium triethanol amine and lactate showed significant enhancements in shear and thermal stability with synthetic polymer-based systems. The results also show and discuss the influence of systematically changing crosslinker ligand order in CMHPG and synthetic polymer-based fracturing fluids. The work studies the influence of the zirconium crosslinker chemical structure on the rheological properties of both biopolymer and synthetic polymer-based fracturing fluids. The performance evaluation shows that delay time, shear and thermal stability can be enhanced by manufacturing the appropriate crosslinker chemical structure, thus reducing additional additives required used and saving cost.