In recent years, the oil and gas industry has gained greater operational efficiencies and productivity by deploying advanced technologies, such as smart sensors, data analytics, artificial intelligence and machine learning — all linked via Internet of Things connectivity. This transformation is profound, but just starting. Leading offshore E&P operators envision using such applications to help drive their production costs to as low as $7 per barrel or less. A large North Sea operator among them successfully deployed a low-manned platform in the Ivar Aasen field in December 2016, operating it via redundant control rooms — one on the platform, the other onshore 1,000 kilometers away in Trondheim, Norway. In January 2019, the offshore control room operators handed over the platform's control to the onshore operators, and it is now managed exclusively from the onshore one. One particular application — remote condition monitoring of equipment — supports a proactive, more predictive condition-based maintenance program, which is helping to ensure equipment availability, maximize utilization, and find ways to improve performance. This paper will explain the use case in greater detail, including insights into how artificial intelligence and machine learning are incorporated into this operational model. Also described will be the application of a closed-loop lifecycle platform management model, using the concepts of digital twins from pre-FEED and FEED phases through construction, commissioning, and an expected lifecycle spanning 20 years of operations. It is derived from an update to a paper presented at the 2018 SPE Offshore Technology Conference (OTC) that introduced the use case in its 2017-18 operating model, but that was before the debut of the platform's exclusive monitoring of its operations by its onshore control room.

Hydrocarbons are trapped at great depths with pressure and temperature higher than surface conditions which would vary depending on reservoir properties. When the well is set on production, these hydrocarbons travel through the wellbore over reducing geothermal and formation pressure gradients. Hence, at shallower depths the temperature drops below the cloud point and sometimes, below pour point of crude thus creating an ambient temperature for the formation of wax and deposition of paraffin on the inner side of production tubing. It has been observed that when hot fluid passes through a pipe which is covered by a continuously circulating hot water bath, the temperature difference of the fluid at surface outlet and sub-surface reservoir is reduced to a minimal value. This paper therefore proposes a practical application of such heat transfer within a wellbore for passively solving major industrial issues of paraffin depositions. The idea lies in minimizing the heat losses, which can be effectively done by insulating the inner side of the casing so that the annulus and fluid flowing within the tubing is isolated from exterior losses. According to the First law of Thermodynamics the fluid flowing within the tubing will experience reduction in thermal gradient. These loses can be compensated by injecting hotter brine through a pipe at the bottom of the annulus, which is isolated, using production packer. Further, circulating hot fluid in the annulus would result in isothermal heating of the fluid flowing through the tube which would minimize the heat loss across tubing, causing an increase in temperature of fluid at the surface above pour point. Several researchers have put forth heat transfer equations across the tubing's, annulus, insulator, casing, cement and the formation which can be used to calculate the overall heat transfer coefficient and thus, the amount of heat losses. Quartz sensors placed at the bottom of a wellbore would detect bottom borehole temperature based on which the injection temperature of fluid can be manipulated. The entire process can be automated by applying an artificial intelligent system which would monitor, control and respond. This method would increase the capex but would decrease the operating cost thus leading to an increase in the life of the well.

Radial jet drilling is a widely used environment friendly technique to improve well productivity in tight reservoirs, accelerate production in low-to-medium permeability wells, revamp production in mature wells with formation damage. This technique has helped to enhance production from mature field by bypassing skin, extend the connectivity of the wellbore beyond the near well bore area by drilling laterals using high pressure water jet, and thereby alleviate production restrictions caused by near well bore damage and extend the reach of the wellbore far into the formation. Production, being dependent on reservoir contact of the well bore is therefore increased as average reservoir contact is enhanced by the drain holes. However, selection is equally important as all wells cannot be considered as a suitable candidate and unsuitable candidate selection can show detrimental outcomes. The technology was applied in a sandstone reservoir where a 22 mm hole was created in the casing at the target depth and then 50 mm OD lateral of length 100m was drilled in the reservoir using high pressure hydraulic jet. The accurate placement and orientation of downhole tool plays a significant role in the success of this technology and is found to be always challenging. Preventing casing milling in undesired azimuths, eliminating chances of lateral overlapping are some challenges that essential to be addressed for gaining optimum advantages. One of the promising technologies to address these challenges was the application of Surface Recording Gyro System. The application of surface recording gyroscopic well bore navigation system provides accurate placement of tool for lateral exit in the down hole and thus enable creation of lateral in the desired direction. This paper discusses candidate selection and execution carried out in 7 nos. of wells in OIL INDIA LIMITED utilizing surface read out gyro system, which was done for the first time in INDIA . This paper also discusses about a post job analysis and lesson learnt with depths varying from 2414m to 3472m , the deepest well in India where radial drilling was carried out successfully. Post radial drilling on wells which had no/poor production prior to radial drilling showed very encouraging results. It also details about criteria of well selection, step by step procedure of the process, bottom hole tool selection, jetting and milling fluid used along with function, application, advantages of surface read out gyro system. As stimulations and well preparation in complicated wells are capital intensive, it was critical to identify the most-suitable candidates with the available dataset before attempting well preparation and further acquisition. This was addressed through a customized workflow to design and creation of the horizontal laterals in desired azimuth utilizing the surface readout gyro system along with radial jet drilling for maximizing oil recovery.

In an offshore field, mitigation of H 2 S from natural gas itself is a big challenge. A situation where high H 2 S present in well fluid increases the challenges several fold to sweet both processed oil and gas. In a wellhead platform/remote location where manual intervention requirement is minimal, conventional process has several limitation such as space availability, load on structure, frequent monitoring etc., hence may not be suitable for mitigation of H 2 S from processed gas and oil. In this work, an approach is adopted for sweetening of sour gas and sour crude in an optimum way, keeping offshore constraints in mind and without usage of rotating equipment's. An integrated simulation model is developed in Aspen HYSYS process simulator wherein well fluid from well manifold is processed in three phase oil and gas separator. The gas liberated from the separator is first sweetened in adsorption columns considering three bed systems unlike general usage of two. The oil is sweetened in an envisaged stripper column utilizing sweet gas from adsorption column as stripping gas. In this work, a three bed adsorption column is envisaged wherein 1 st two column in used for sweetening of gas liberated from separator which consists of around 7500ppm H 2 S. Sour oil from the separator which contains around 2000 ppm of dissolved H 2 S is processed in a stripper column for mitigation of H 2 S dissolved in the oil. Sweet gas liberated from 1 st two column of adsorber bed is used as stripping gas for oil sweetening. H 2 S liberated from stripper column is routed to the 3 rd column for sweetening. After this gas from all the adsorber column is combined and routed to process platform along with the sweet oil. Analysis reveals that, this scheme can sweeten altogether both oil and gas to the desired H 2 S level without the need of any rotating equipment's and must be a suitable for remote location. A holistic approach was taken for sweetening of oil and gas without the need of any rotating equipment's, & any chemicals, unlike the conventional method and hence can be suitably adopted for an offshore environment or at remote location where requirement of manual intervention is bare minimum.

After years of development, qualification and engineering, subsea compression technology is now a proven solution to increase the recovery factor for offshore gas developments. The first subsea compression system was installed at the Aasgard field in the Norwegian Sea, which was started up successfully on the 17 th. of September 2015. This project represents an important milestone for the oil and gas industry, as apart from representing the successful developments of new subsea processing technologies, subsea compression also proves itself a viable alternative field development option to oil and gas operators. The experience from Aasgard enables tomorrow’s subsea compression solutions. The basis is increased field recovery by subsea compression. In addition it opens for wells stream and deep water applications, as well as CO 2 EOR. This paper aims to share Aker Solutions’ experience on Aasgard Subsea Compression project, from the design and the project execution phases up to the operational phase, highlighting the key learnings from more than 50 000 hours of successful subsea operation. In addition, the paper will also describe the ongoing development activities to optimize the compression system delivered for Aasgard, with particular focus on increased field recovery and unit size and weight optimization without requiring qualification activities of new technologies. This new generation of subsea compression system will extend the applicability of this technology to a much wider range of fields and offshore regions.

Wellbore integrity is very critical in oil and gas industry and needs to be maintained through the entire cycle of well's life. The most important item for well integrity is to set cement between two casings or between casing and formation. A good cement job provides isolation and protection for the well and a poor cement job can have cracks and allows corrosive fluids to migrate through micro channels. Downhole casing repair is a common workover operations worldwide, especially in wells that have been producing over number of years. It is very challenging to control corrosive fluid migration which slowly corrodes casing and tubing over time. An innovative epoxy resin formulations has been developed and tested in the field to repair casing leaks which is extremely easy to handle and very economical. A cost-effective workover program can be developed and implemented depending on the severity of the leak. The improved approach of using innovative resin can be used by mixing with cement blends to repair major casing damage and can also be used as standalone application to fix minor leaks. The system maintains extremely good rheological properties even when mixed with cement. The system has ability to withstand high differential pressure and is also resistant to acid, salts, hydrocarbons and most importantly various corrosive liquids. The precise application is determined by measuring the injectivity of the well. In the low injectivity wells, only epoxy resin solution will be spotted and repair the damaged casing. In the high injectivity wells, the chemical will be mixed with cement and completely seal the damaged zone. The chemical will enhance the mechanical properties of the cement and will be more resilient to extreme down-hole condition. The paper will emphasize the added value and potential of the method in restoring the casing integrity. The paper will also discuss the laboratory test reports and application which will highlight effective and economical outcome.

The identification of fluid saturations in depleted reservoir sands is critical to understand the reservoir potential and field life. However, in case of water flooding, the formation water salinity of the reservoirs sands might be altered and fluid saturations from conventional petrophysical analysis can be misleading. This will have direct impact on the field economics. A salinity independent saturation computation from Carbon/Oxygen (C/O) log becomes a necessity in such development wells– a first of such application in a field under secondary recovery for this basin. C/O well logging has been extensively used in cased hole environments to determine saturation behind casing. They are used essentially to determine oil saturation in cased hole conditions for depleted reservoirs. While their cased hole applications have been well established; for the study well, a pulsed neutron tool was used in an open hole environment to determine the fluid saturations to compare against the saturations computed from conventional resistivity logs. This study helped in the determination of fluid saturations in mixed salinity reservoir sands, which were to be explored from subsequent wells in the field. The hydrocarbon-bearing sands in the field were water injected in nearby wells to enhance recovery. Development wells drilled in the field relied on petrophysical evaluation from conventional open hole data and pressure testing and fluid sampling depths were determined accordingly. A pulsed neutron tool was deployed in an open hole well after operational constraints were encountered with the formation testing tool. As an alternative, the pulsed neutron data were acquired in the well to compute salinity independent water saturation based on C/O log response as against the fluid saturation computation from resistivity logs. The determination of fluid saturations from C/O helped in determination of altered salinity for the sand intervals in the field. For the study well, C/O-derived water saturation was found to be higher than that from resistivity log computation. This was significant in identification of water breakthrough in the bottom interval of the reservoir sands. This paper details the method and findings of C/O logging in open hole environment from Western Onland Basin in India. The critical solutions provided for the reservoir sands in the field and enabled the operator to save significant well cost and rig time by making informed decision of not lowering the casing in this well section.

In 2018, an operator in Malaysia completed a sidetrack campaign consisting of injector wells. These wells were planned for maximum productivity via sustainable wellbore zonal isolation. The presence of Carbon Dioxide (CO 2 ) in these wells elevated concern about the zonal isolation of cement across the interval. Moreover, for an injector well, the cement must exhibit resilient properties by design of enhanced mechanical properties to provide long-term isolation based on a cyclic wellbore. An advanced slurry system was designed that enabled the set cement to manifest superior properties in three parameters—corrosion resistance against CO 2 , flexibility against wellbore stress changes, and expansion to mitigate microannuli. The design of the slag-based flexible cement system with expanding additive (slag-flex) considered all three parameters in the fit-for-purpose application of a resilient and flexible expansive cement system in a CO 2 -rich well. The system’s mechanical properties, such as Young’s Modulus, Poisson’s Ratio, and tensile strength, were verified with laboratory-scale testing and validation against stress analysis software to confirm on the resilient and flexible properties. The laboratory testing result demonstrated the improved properties of the system, including high tensile strength and low Young’s modulus. Furthermore, the reduced water content of the system decreases the permeability of set cement and thus increases resistance towards corrosive substance such as CO 2 . For certain cases in the past, two separate slurry systems had to be designed—a lead slurry with CO 2 -resistant properties and a tail slurry with flexible and resilient properties. Often, several issues arose from this practice, including complex logistics due to cement silo blend arrangement and complexity during job execution. Hence, this new system presents a novel idea and methodology that will deliver value to the oilfield industry by integrating CO 2 resistance, flexibility and expansion properties in a single slurry system. The system was successfully pumped in wells in Malaysia; no sustained casing pressure has been recorded to date, and wells have been delivered to their intended zonal isolation requirements without compromising well design and overall integrity. This is an innovative application of this type of cement system in the region, and the long-term zonal isolation and well integrity assurance in these and future wells have the potential to save millions of dollars in remedial work. The cement system is currently recognized as the default technology for CO 2 -rich injector wells in Malaysia.

Enhanced Oil Recovery is important stage of life cycle of a field and often it is implemented with challenges. In the chemical EOR, challenges and surprises are expected in production chemistry and production facilities operations. Partially hydrolyzed polyacrylamide used widely for controlling mobility ratio so that Operator is able to recover maximum possible oil. With complex water chemistry and rich in positively charged divalent ions, flooded polymer having negative charge interacts with divalent ions of produced water. Back produced sheared polymer interacts with divalent ions to form semi hard to hard scales poses challenges of the reliability of production facilities. Other important limitations to be noted in CEOR phase are using production chemicals to control scale, emulsion and microbial treatment under Hydrogen Sulphide and waxy crude environment. This paper discusses about the requirement of preparedness and how to overcome challenges of EOR operations and in handling the back produced polymer in following areas: Selection of production chemicals to be compatible to polymer so that no or minimal degradation or loss of viscosity due to polarity of chemicals Performance of production chemicals in the presence of polymer Solids loading in production system Emulsion and produced water treatment Suitability of produced water treatment facilities Revised scaling and fouling control with back produced polymer with rich divalent ions present in produced water Strategizing chemical management system to suit polymer flood and polymerized back produced water treatment regime

With the onset of water production, mineral scale deposition appears in the oil and gas wells. The scale deposition in wellbores and flow lines is a universal challenge that has to be addressed with technical and economical effectiveness. Efforts are ongoing to effectively inhibit the scales or remove them through chemical or mechanical means. Kuwait Oil Company is planning to improve the production to 4.0 MM BOPD by the year 2020. In this pursuit, all the possible efforts are made to increase production including application of new technology in drilling, completion, well production and facilities. One of the key aspects of production improvement from individual wells is to avoid any obstruction in the wellbore, wellhead and flow lines that might affect the smooth flow of hydrocarbons. This includes the augmented steps on eliminating mineral deposition from wellbore and flow lines. The wells are suffering from frequent scale deposition in wellbore and flow lines. Usually these problems are mitigated by using strong acid. However, due to maturing of field the wells are generally completed with ESPs. When acids like HCl are used, these ESPs are corroded severely adding extra cost of workover and production loss. This challenge is driving the operators to use less aggressive chemicals that remain environmentally friendly and can maintain the integrity of submersible pumps, metallurgy of the flow lines and other components. To meet this challenge, various chemicals were evaluated through laboratory tests and case histories. The chemical composed of Glutamic acid was selected for the first pilot. The pieces of tubular and other well components suffering from scale deposition were tested in the lab and the results were found to be highly encouraging. Based on this a pilot campaign was initiated with a batch of eight wells to treat wellbore and flow lines. All the treatments were found highly successful. Due to this treatment, the daily production has been improved to 5,000 BOPD without any extra activity such as replacement of ESP or flow line tubing due to corrosion. The paper presents the technology evaluation process, lab testing and field trial results.

Multiple analysis has indicated that over 50% of the oil production in the next 20-25 years is going to be produced through enhanced recovery procedures including polymer flooding. The heuristics for polymer flooding says that it is feasible to apply polymer flooding in reservoirs having oil viscosities in the range of 10 to 150 mPa.s. The main factor limiting this heuristic limit for polymer floods is that the injected water viscosity required for higher mobility ratio leads to pumping inefficiencies and low polymer injectivity rates. In this paper, we suggest a supramolecule based on the complexation of a long-chain amino-amide and maleic acid which can adjust its viscosity values reversibly to overcome the heuristic problem related to polymer floods. The concept is fundamentally based on the fact the supramolecule system which is injected in the reservoir will initially be maintained at a low viscosity and on application of external pH stimuli will increase in viscosity values prior to contact with oil. Our laboratory studies indicate that such a system is also tolerant to high temperatures and salinities Popular polymer systems used floe EOR purposes on experiencing extreme shear stresses and temperature break-up and degrade, however the supramolecule system dissemble and reassemble making the supramolecular system "healable" in a manner. The supramolecular systems can also adapt to confining environments, for example, on flow through narrow channels, the supramolecules undergo molecular scission. The supramolecules proposed could be used for viscous oil in thin oil sand zones, permafrost and other environmentally constraining systems. This paper primarily focusses, on the development and properties of a novel supramolecular system which has adjustable viscosities and interfacial properties and can be resistant to high temperatures and salinities. This Supramolecular system can significantly improve the feasibility and cost-effectiveness of a polymer flood process and can be utilized universally.

Unconventional Horizontal Multistage Fracture Completions have a vast acceptance worldwide and is proven in various Geographical and Geological setups in producing the Initial Oil and Gas in Place . The most immense method of conducting the Multistage Horizontal Fracturing operations is through the "Plug and Perf" method. This technique is one of the most practiced way of conducting the operations in a time effective and a safe manner. This usually entails a conveyance method with threaded joints or Coiled Tubing. Other conveyance methods can also be Electric Line, however Coiled Tubing/Threaded Joint is needed for the later part of operations to bring the well online for production. The Coiled Tubing is a fast and effective way to complete the operations necessary for achieving the well design targets. Currently most of the operations are done in the same fashion, where most of the operational problems are not counted in while planning initially. This paper will give an insight on the optimization of such operations in Horizontal Wells and especially wells with an angle more than 90°. This paper will describe the optimizations done to make the operations much more time effective and efficient in terms of equipment and resources through field experience and published data. These optimizations can be utilized for pre-job designs, Well Bore Clean Outs (WBCU), CP Setting, Motor Design, Mill Design, Milling parameters, Extended Reach Issues and Post Milling Practices.

Mumbai Offshore fields are consisting of heterogeneous limestone reservoirs. Some of the reservoirs consist of tight carbonate with poor wellbore transmissibility. With the maturity of the fields, improving production from tight reservoirs has become the main focus for sustaining overall production. However, the responses of conventional stimulation techniques such as matrix acidization with self-diverting acid, deep penetrated acid, conventional acid fracturing etc. are not very encouraging in a tight reservoir, which calls for novel stimulation approach. To address the issues, reservoir properties, well completion strategies and previous stimulation practices were analyzed in collaborative approach. Based on analysis, a different stimulation approach Closed Fracture Acidizing (CFA) was identified as the potential technique. Closed Fracture Acidizing reopens previously created fracture system with a pre pad fluid pumped at high rates. It involves creating fractures with a viscous fluid, letting it close followed by pumping a suitable acid system at matrix rate for etching the fractures. To improve treatment efficiency vis-à-vis better etched conductivity, different techniques such as leak-off control additives, effective diversion system, viscous acid systems etc. are applied. For application of the technique, some low producing wells completed in Mukta pay of Heera field, A1 and L1 layers of Mumbai High field and Panvel pay of B-192 field were identified. The well specific treatments were designed by using Cross-linked Guar gel for creating fractures and a customized foamed acid system for etching of fracture faces. Foamed acid has been selected in these treatments for better exposure of acids in the entire fracture network and effective flow back of the treatment fluids. The foamed acid was customized by using a viscoelastic surfactant (VES) as foaming as well as viscosifying agent. Converting the acid system to stable foam greatly controlled fluid leak-off, increased the effective fluid volume and retarded the reaction rate, which is desirable in carbonate reservoirs. The various additives such as cross-linker, breaker etc. were optimized at onboard laboratory in the well stimulation vessel. The jobs have been implemented in ten wells under constant monitoring of treatment parameters during fracturing, closure and acidization. Post CFA jobs indicate 670 bbl/day of oil production from a non-flowing well and significant improvement of productivity in other wells. This paper describes the details of Closed Fracture Acidizing technique, treatment design, lessons learned during execution and results. The novelty of the approach over the conventional stimulation techniques in tight carbonate reservoirs are the treatment methodology and use of foamed acid system for better acid etched fracture conductivity.

Sustained casing pressure, otherwise known as casing-casing annulus (CCA) pressure, is a common problem encountered in the deep, high pressure, high temperature (HPHT) gas fields of Saudi Arabia, and in many other locations globally. Although many solutions have been tried in these fields over the years, none of the existing solutions have proven to be 100% effective. A new solution has recently been implemented in Saudi Arabian gas fields that features a combination of heavy-weight cement blends greater than 21ppg and a polymer resin to improve the mechanical properties of the cement, especially the shear bond, to prevent the CCA pressure. Polymer resin is also resistant to hydrocarbons, acids, and salts, enabling the cement-resin system to be placed in harsh environments. This resistance will help to maintain a dependable barrier throughout the life of the well. This paper presents a case history of the application of this heavy-weight cement-resin (HWCR) system in the Saudi Arabia Harradh field where the failure of a differential valve (DV)packer meant that there would be no redundancy backup should the cement fail to provide a full barrier in the annulus. The paper describes the process used to design the HWCR system and how its application is critical to the success of the job.

Declining reservoir pressure, increasing water cuts along with dwindling well counts pose a serious challenge to any mature oil and gas field in sustaining production. In low oil price scenarios, enhancing production using conventional approaches like workover and interventions becomes challenging due to associated costs. This provided an opportunity to look for alternate approaches that are cost-effective and would help to manage these issues on a continuous basis. This paper presents techniques for augmenting productivity of well stock by mitigating a range of issues causing production losses using cost effective, easy to implement chemical based techniques. These techniques have helped the asset to significantly arrest its production decline in the late life phase. This paper details the approach for identification of issues, selection and field implementation of right chemicals and the benefits that were realized from such applications. Case studies from BG Exploration and Production India Limited (BGEPIL) operated field in Mumbai offshore region are incorporated in this paper to highlight the effectiveness of chemical based approach in mitigating losses right from reservoir to processing platform. Some of the production issues in this mature field which have been successfully resolved using chemical based techniques are: Reservoir: ○ Loss of well stock due to Downhole emulsion issue Well: ○ Calcite Scaling deposition in wells and topsides ○ Liquid loading of High Gas Liquid Ratio wells Pipelines: ○ Back Pressure on wells due to Pipeline size limitation Processing Facilities: ○ Deterioration in Heat Exchanger performance due to fouling Process adopted includes field data acquisition, analysis using real time state-of-the-art network and process models to identify the root cause of these issues. Results from both steady state and transient models were used to select the appropriate chemicals, conduct field trials / implementation and set the success KPI's accordingly. This paper offers a holistic approach on resolving each of the discussed production issues utilizing the best available technology in the market. Trials and implementation of the various chemicals in the field have added a significant value to the asset; both by protecting and enhancing the current production. More than 20 % of current field production is directly attributed to these chemical applications and expected to add more share of production in a far more challenging phase of mature asset. The approach discussed here for each of such production issues along with the challenges that were faced during implementation will enable other assets to tackle these problems with a more cost effective and easy to implement solutions especially in low oil price environment.

Worldwide partially hydrolyzed polyacrylamides (HPAM) are preferentially used for polymer-based enhanced oil recovery (EOR) processes, due to cost-competiveness. However in recent past several reports suggested that there are certain issues associated with treatment of produced water – post HPAM applications such as, oil-water separation due to emulsions and toxicity associated with degradation products of HPAM, such as acrylamides. Biopolymers are biodegradable and environmental friendly alternative to chemical polymers used for EOR applications. In present work we studied the biopolymer-pullulan production by fungal isolates of Aureobasidium pullulans , isolated from Oman, partial structural characterization and potential applications in Microbial Enhanced Oil Recovery (MEOR). Different production media containing carbohydrate based carbon sources were screened for better biopolymer production. During the course of experiments we studied fungal growth profile and biopolymer production under different conditions, and rheological properties of biopolymer, chemical characterization and application of biopolymer in enhancing oil recovery using Berea sandstone cores. The observed growth and production temperature was up to 35 °C and optimum was at 30 °C for Omani A. pullulans isolates. The better growth was observed under shaking conditions. A. pullulans strains are reported to produce a type of biopolymer – pullulan. Thus samples were analyzed from Omani isolates for biopolymer production using rheological studies for any changes in viscosities with respect to time. The cell-free broth showed increase in viscosity from 1-4 cP of the abiotic control production media (without biopolymer) to 28-59.9 cP of the cell free broth at 25 °C. The initial yield of crude extracted biopolymer was ≥12.68 g/L. The biopolymer was extracted in crude form and partially identified by Fourier transform infrared spectroscopy (FTIR), which showed similarity in chemical structure with reference standard pullulan from Sigma, USA. When this biopolymer-pullulan was used for MEOR studies using Berea core-plugs in core-flooding experiments, it recovered additional 9.4% oil over residual oil saturation (S or ).

The production strategy in the Nong-Yao field considered the unconsolidated nature of the reservoirs and an effective drawdown strategy given the use of Electrical Submersible Pump (ESP) for artificial lift. The particle size distribution analysis demonstrated a broad range of sand grain size that would ideally require sand control methods like gravel packing which was not preferred due to cost and complexity. A simpler and cost-effective solution using an advanced sand screen technology was implemented. Applying a minimum drawdown across horizontal inflow across the sand face via gradual increase of ESP frequency was initially adopted to complement the use of screen only completion. The specially designed sand screen with compressed metal-wool was installed in 14 wells in the Nong Yao field. All wells were completed with ESP for artificial lift. After one year of production, the wells have produced sand free with no sand observed at surface, even though some wells are high water-cuts and ESP frequencies have been ramped up. Analysis performed using downhole ESP pressure data indicate very low draw-down across the sand face, suggesting no issues with downhole plugging of the screens. This observation shows that the implemented completion design, along with the production start-up strategy is working well. This same strategy is being applied in the next phase of the field development. This is the first application of the compressed metal-wool sand screen in the Gulf of Thailand. The analysis and deployment of this sand control method to fit the reservoir sand characteristics, in combination with artificial lift and production strategy to meet operational challenges, to reduce development cost and to achieve production performance. The success achieved with this in the Nong Yao field could be extended to other marginal field developments, which have similar sand face completion challenges.

Even in the 21 st century, the oil industry is yet to overcome some major problems it faces related to oil spill cleanup. Oil spills can cause a multitude of problems for the environment which may even last for decades after the spill occurs. This paper discusses a novel approach that may provide a complete solution to combat oil spills. Conventional techniques are not adequate to solve the problems of massive oil spills. Graphene based aerogels or Aerographene have attracted widespread attention due to its excellent oleophilicity, hydrophobicity, reusability, high uptake rate of oil, high uptake capacity and recovery of oil. Although the application of graphene aerogel for an oil spill is still in its nascent stage, it offers great promise for the future. It is believed to have potential to replace present sorbents which are used commercially. This paper briefly outlines present oil spill cleanup techniques and problems associated with each technique. A major part of this paper will be on the evaluation of aerographene properties and how it overcomes major problems related to conventional techniques. Many properties of aerographene have been studied which makes aerographene stand a chance of replacing the present oil spill cleanup methods. This paper presents a novel idea by which cleaning up oil spills with the help of aerographene will become much simpler, easier, cheaper and will prevent the environment from degrading at a massive scale due to oil spills.

ASP flooding process has emerged as cheaper alternative of conventional micellar–polymer flooding. Process has economically produced incremental oil over water flood in field on pilot scale by reducing the capillary forces trapping the oil and improving the overall contact efficiency. Process is designed to combine the best feature and eliminates some of negative aspect of each process of Alkaline, Surfactant and Polymer flooding. Present paper deals with the application of ASP technology in Viraj field of Ahmedabad Asset. The Viraj rock is sandstone rock with average porosity is 30% and permeability ranges 1-10 Darcy. The reservoir crude has viscosity of 50 cP at reservoir temperature of 81°c with acid number of1.805 milligram per gram of crude oil. Viraj crude is viscous in nature. Hence sharp viscosity/mobility contrast is exiting in primary production mechanism. In view of above, ASP process appears to be best feasible technology for maximizing the ultimate recovery. A four inverted 5-spot pattern has designed on the basis of encouraging laboratory results. Conventional method of reservoir engineering were applied for performance prediction of oil recovery in the field condition and an additional recovery was estimated 18% of pilot OIIP over water flood (32%). Surface facility and injection schedule was prepared by in-house expertise. ASP plant has been commissioned on 10 th August-2002. An MDT team was formed for monitoring the ASP pilot accordingly a monitoring manual was prepared for surveillance. Polymer samples were collected from polymer storage tank, after pumps and at injector well heads for quality control of injection polymer. Wells head samples of all 9 pilot producers and some offset well were carried out for tracer breakthrough/ injected chemicals break through to know the flood front advancement. Three different type of tracers were injected in three injectors followed by ASP slug injection @ 200 m 3 /d per well. It was estimated that 58000 m 3 of additional oil was produced and decrease in water cut of about 10% by ASP process. Before implementation the ASP pilot in July'2002, the liquid production was at its highest@ 1560 m 3 /d and corresponding oil rate and water cut were 152 m 3 /d and 89%. After implementation of ASP pilot, water cut declined to 72% by April'2003 and oil production increased to 260 m 3 /d, indicating the efficiency of ASP flooding. Subsequent rise in liquid withdrawal could not contain water cut rise and regained a level of 80%+. The tracer and chemical breakthrough was observed in almost all the pilot producers and some offset wells. It showed that front was moved uniformly in all direction, same was confirmed later by simulation study. During the pilot implementation imbalance in injection and liquid production was observed due to completion problems of five producer in both the layers, as confirmed by simulation study in April' 2010. Simulation study validated the decreases in oil saturation in pilot area by moving the mobile oil towards down-dip side of structure. This mobile oil by ASP slug was trapped by drilling 9 infill locations and on sidetrack wells. This has led to increased oil production from 100 m 3 /d in March'2010 to a level of 160 m 3 /d whereas water cut has remained more or less at around 83%. The cumulative oil produced by these ten infill locations was 98476 m 3 as on Nov'2015. A total oil production by EOR and mobilized oil obtained by IOR (infill locations) was 156476 m 3 which is about 87% of envisaged oil production from pilot. The success of this first ASP pilot tested in Viraj field of Ahmedabad Asset, India led field pilot expansion for commercialization.

Well and Reservoir Management activities are crucial to maintain production targets of a maturing field. Cairn manages ~600 active wells in Rajasthan in which approximately 3000 well interventions are executed annually. To facilitate the safe delivery of this large number of interventions and maintaining focus on sound engineering practices, the automation of standardized activities was initiated and a "Well Intervention Planning and Execution" portal was developed with the objective to reduce the man-hours spent on data collection, archiving, performance tracking and MIS management, that could divert valuable time and effort to detailed engineering, problem identification, solution identification and post job evaluations. This paper highlights the thought process, workflow and value drivers for the design and implementation of an automated well intervention management process and details the benefits realized.