bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Concurrent Heat Transfer within the Wellbore for Passively Enhancing Oil Recovery by Reducing Deposition of Heavy Components of Crude
Authors: Sahu Ajay Kumar
Published: April 2019

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.
Mitigation of Foaming by Using Pressure Pulse Technique
Authors: Jakkulwar Avi Diliprao , Das Barnali , Sengupta Partha , Santoshrao Pawar Anilkumar , Deuri Budhin
Published: April 2019

Foaming in absorber column for sour gas treatment using amine is a common problem which adversely affects column performance leading to reduction in sales and fuel-gas production and solvent loss. Mostly antifoam injection has been a common method to counter the foaming, large dosage and frequent dosing of antifoam many a times aggravates the problem. This study details an alternative technique based on pressure pulse mechanism to control foaming in one of ONGC's gas sweetening plants.

One of ONGC's amine based sour gas sweetening plants faced severe foaming problem frequently. The feed rate is 200 kscm/hr and absorber column operating pressure is 51 kg/cm2. The experiment utilizes the property of surface tension which fluctuates with change in pressure of the system leading to foam collapse. The experimental procedure involved varying the sour gas feed rate, thereby creating pressure pulse inside the absorber column. Differential pressure across the column which is an indicator of foaming tendency is then monitored and controlled within 1.0 kg/cm2 and recorded for establishing effectiveness of the method.

It is observed that by providing a number of cycles of pressure pulse in the absorber, the differential pressure stabilizes gradually which indicates collapse of foam. It shows that whenever there is increase in feed, expansion of bubble takes place which provides high interfacial liquid-vapour contact. On the other hand whenever there is decrease in feed rate, compression of bubble takes place which provides low interfacial liquid-vapour contact. Surface layer surrounding the bubbles in a foam acts as a membrane or skin that can stretch or relax in response to change in pressure and gives a mechanical shock which breaks the bubble. The increase of size ultimately leads to instability and break-up of the upper surface and releases the liquid holdup. Hence by using feed rate spikes, the pressure of the bubble is pulsed to higher levels and returned to substantially the original level. This cycle continues for a selected number of times so that this pressure pulse travels through the liquid and bubbles and affects its surface tension. This results into a transition phase which in very high energy level breaks the bubble and releases the gas and decreases the liquid hold up and controls the foaming phenomenon.

This paper will gives an insight into a novel methodology of mitigating foaming problem in a sour gas treating absorber just by varying the feed rates in a controlled manner. This technique eliminates the need for injecting antifoam agents which in turn will reduce the operating expenditure of the plant. Adverse impact on environment due to excessive use of antifoam agent is also minimized.
Pre-Laying of Flexible Lines Flownline and Riser and Floaters in Ultra Deepwater
Authors: Melilo Junior Angelo Celio , Oliveira da Costa Carlos Henrique , Armani Delalibera Carlos Alberto , Schwingel Dias Marco Antônio , Palmeira de Oliveira Thomaz Murrieta , Pereira Rafael Merenda
Published: April 2019

The Libra Extend Well Test (EWT) project is composed of 2 satellite wells interconnected to an FPSO with an external Turret anchor. One well is the producer, with 6-inch service lines and 8-inch production line in lazy wave risers configuration. The other well is the injector, with two 6-inch gas flow lines also in lazy wave compliant configuration. In the project planning several ac-tions were considered in order to guarantee the first oil date determined by the project, while the production unit (FPSO) was not available in the location and ready to pull-in campaign. One of these actions studied and later adopted was the pre-laying operation of the flexible lines with floaters in the lazy wave configuration of the production line of the production well. Later on, simi-lar studies were done considering the pre-laying of injection lines also. As this type of operation is not a track records at Petrobras for the ultra-deep water scenario, additional studies were nec-essary to ensure its feasibility and the safety execution. The objective of this article is to present the previous studies and the result achieved in the pre-laying operation of flexible line with float-ers in the lazy wave configuration of the Libra EWT service line.
Role of Culture, Processes and Systems for Safe Operations in Upstream Sector
Authors: Verma Prem Kumar
Published: April 2019

Upstream Oil & Gas Industry has witnessed improved HSE performance over time, by adopting latest technology and standards, engineering improvements, including hardware and adopting new processes and systems with maximum emphasis on safety with very good management systems. Compliance and audits have also improved a lot. However, improvement in culture, behavior and commitment at all levels are very important to deliver better business value in Personal and process safety.

Global energy risk engineering companies collate accident data over years and it is very clear that accidents continue to happen, which forces us to think methodology to improve personnel and process safety aspects continuously. It is observed that we are poor in assessing risk as we become used to risk, which could be due to over confidence, ignorance and safety culture issues. As per IOGP Incident Statistics, upstream process has improved over years, while we need to further improve in drilling operations.

It has been seen that Oil & Gas drilling industry is implementing personnel safety very rigorously with greater awareness, certified training programs, advanced technology, mock drills etc. However, Process safety in drilling industry needs greater emphasis. Some of the processes i.e. safety case, Risk and Control register with risk identification, assessment, response, financial impact, control, remediation and self-verification needs to be pursued rigorously. Processes and systems with organizational structure, quality of engineering decisions and understanding safety risk Vs commercial risk and suitable mitigation measures need to be pursued further. Decision hazards are very important to be analyzed including the process and lessons learnt. In addition to above, the basics of safety and the culture of caring for self, colleagues and the Assets are very important aspects.

This paper discusses the culture, processes and systems for safe operations in the upstream industry with special reference to drilling and completion operations.
Accurate Production Profiling in Deviated ESP Wells Affected with Recirculation with Advanced Production LoggingTool
Authors: Agrawal Gaurav , Kumar Ajit , Mishra Siddharth , Dutta Shaktim , Khambra Isha , Chaudhary Sunil , Sarma K. V. , Murthy M. S.
Published: April 2019

Objectives/Scope: XYZ is one of the marginal fields of Mumbai Offshore Basin located in western continental shelf of India. Wells in this field were put on ESP for increasing the production. Regular production profiling with traditional production logging was done in these wells to ascertain the water producing zones if any and do the subsequent well intervention if required.

Methods, Procedures, Process: In few deviated wells with low reservoir pressure, low flow rates and large casing size, massive recirculation was observed due to which spinner readings were highly affected. In such scenarios, quantitative interpretation with conventional production logging is highly difficult. Only qualitative interpretation based on temperature and holdup measurements can be made which might not completely fulfill the objective. In one of the deviated wells, massive recirculation was observed due to large casing size. Recirculation on ESP wells is generally not expected due to high energy pressure drawdown exerted on the well. Traditional production logging imposed difficulty in interpretation due to recirculation. Only qualitative interpretation was made from temperature and holdup measurements. Hence advanced production logging tool called Flow Scan Imager (FSI*) with 5 minispinners, 6 sets of electrical and optical probes, designed for highly deviated and horizontal wells to delineate flow affected due to well trajectory, was suggested for quantitative interpretation in such wells suffering with recirculation.

Results, Observations, Conclusions: In the next well, production profiling was to be done before ESP installation in similar completion as the last well. Therefore, huge recirculation phenomenon was expected in the well. FSI was proposed in this deviated well with recirculation for production profiling and also for finding out the complex flow regime inside the wellbore. FSI helped in proper visualization of the downhole flow regime with the help of multispinners and probes. Quantitative interpretation was made with the help of FSI data. Also, quantification was confirmed inside the tubing (lesser cross section area) where no recirculation is expected as the mini spinner does not collapse inside the wellbore. In traditional production logging, it is generally not possible due to the collapsing of full bore spinners inside tubing. Better understanding of the flow regime can be obtained with FSI than conventional production logging due to the presence of multiple sensors. Later interventions using FSI results have shown significant oil gains.

Novel/Additive Information: FSI was used in deviated ESP wells with recirculation for production profiling, accurate quantification, better understanding of flow regimes and to take improved well intervention decisions.
Digitization and Automation of Crude Transport Operations for Improved Safety and Security
Authors: Jami Satish , Shah Vishal
Published: April 2019

The rapid progress of technology such as big data and analytics, sensors, and control systems offers oil and gas companies the chance to automate high-cost, dangerous, or error-prone tasks. Most oil and gas operators are starting to capture these opportunities and doing well to accelerate their efforts. Companies that successfully employ automation can significantly improve their bottom line operations.

While automation offers many potential benefits in the upstream value chain of exploration, development, and production and transportation, some of the biggest opportunities are in crude transport operations, such as increased safety, security and decreased down time. Given the increase in oil and gas industry's substantial transport operations, optimizing these operations are essential. Automation creates several opportunities to that end: maximizing accuracy and efficiency in transport operations

This article is based on the application of digital technologies in the field of Crude Oil Transportation for improving Safety and Security while reducing the overall time taken for Crude Transportation Operations at Suvali Onshore Terminal. Digitization and automation of crude transportation operations in oil & gas industry leads to elimination of crude pilferage, elimination of manual errors, efficient crude loading operations, real time monitoring of crude transport operations, ease of measurements, reduction in disruption of crude tanker operations etc
Fractured Basement Characterization: An Integrated Approach for Play to Prospect Analysis and Resource Assessment of Basement Plays
Authors: Singh Manish Kumar , Dubey Siddharth , Chakraborty Subrata
Published: April 2019

This paper presents a multidomain integrated workflow that combines geophysics, borehole geology, fracture modeling, and petroleum systems analysis for characterization and resource assessment of basement plays. A 3D fracture model is developed by integrating image log interpretation and seismic data to assess the reservoir potential of fractured basement. The 3D fracture modeling is done using the discrete fracture network (DFN) approach with image log interpretation and other fracture drivers serving as the main input. The DFN is upscaled to generate fracture porosity and fracture permeability properties in a 3D grid. The upscaled fracture porosity is used to estimate the petroleum initially in place (PIIP) for the prospects. Multiple 2D petroleum system modeling is performed where large fault throws are identified from seismic interpretation. The petroleum system study helps in identification of areas with most prolific hydrocarbon generation and expulsion centers, which, coupled with the cross-fault juxtapositions, are the main locales of charging for basement reservoir. Further analysis of all the elements of basement play (i.e., source, reservoir, seal, trap, and migration) is done, and prospective areas within the basement play are delineated with high geological chance of success.
Planning India's First CO2-EOR Project as Carbon Capture Utilization & Storage: A Step Towards Sustainable Growth
Authors: Mishra Gaurav Kumar , Meena Rakesh Kumar , Mitra Sujit , Saha Kunal , Dhakate Vilas Pandurangji , Prakash Om , Singh Raman Kumar
Published: April 2019

India is the fastest growing major economy and third largest CO2 emitter in the world. Keeping cognizance of country's energy requirement and commitment to climate change, embarking upon technologies having minimal carbon footprint is the need of the hour. Carbon capture, utilization and storage (CCUS) is one such technology which offers dual benefits of carbon sequestration & enhancing oil production from mature oils fields. This paper outlines ONGC's efforts in bringing nation's first CO2-EOR project.

In view of non-availability of natural CO2 sources in India, usage of anthropogenic CO2 captured from thermal power plants was conceptualised. Based upon CO2 source-sink matching exercise and favourable reservoir & fluid parameters, two oil fields were screened. Technical feasibility of CO2-EOR was first ascertained in laboratory by determination of minimum miscibility pressure (MMP) of CO2 through slim tube experiments. Encouraged by laboratory results, full field compositional simulation studies along with fluid characterization inputs from PVT simulator were carried out.

The MMP were found to be in range 190-250 Ksc, which is below the initial reservoir pressures of the targeted reservoirs. The proposed scheme entails drilling of around 70-80 wells inclusive of both producers & injectors and has the potential to yield an incremental recovery between 10-14 %. A sensitivity analysis based upon purity of CO2 and its adverse effect on MMP was carried out in terms of reduced oil recoveries. Since, this shall be a CCUS project, CO2 from the produced stream has to be separated, compressed and reinjected in a closed loop system. Around 5-8 MMT of CO2 will be sequestrated through Structural, Solubility and Residual trapping mechanisms as modelled in compositional simulator. IFT reduction & decrease in Sor (Residual oil saturation) as result of swelling, miscibility of CO2 with native oil were also modelled in simulator. Being first of its kind project in India, there are many inherent challenges to the CCUS project. At the source end, capturing CO2 from flue gas stream and its compression & transportation is a cost and energy intensive process. At the Sink end, CO2 being acidic and corrosive gas will need retrofit modifications in terms of special corrosion resistant metallurgy for existing processing facilities.

The learning curve from this endeavour shall create knowledge base to further expand deployment of CCUS in India, bringing a large portfolio of reservoirs under the ambit of CO2-EOR. Success of CCUS in India will not only increase domestic oil production but also cater to address the National INDC of reducing emission intensity of GDP by 33-35 percent by 2030 as per Paris agreement.
Uncertainty Assessment of Burgan Marrat Carbonate Reservoir using Response Surface Modelling to Plan Early-Stage Field Development
Authors: Al-Shammari Asrar , Gutierrez Jeannire , Sinha Satyendra , Al-Shammari Obaid
Published: April 2019

Burgan Marrat, a deep carbonate reservoir was transferred from exploration to development team for an accelerated production of the newly discovered oil. This multi-billion barrel reservoir is spread over 450 km2, has more than 40 faults, 8 compartments with large variation in oil-water contact and reservoir/fluid characteristics. The objective of this work is to understand the key uncertainties and quantify their impact on the reservoir offtake rate and oil recovery by conducting uncertainty assessment.

An interdisciplinary team identified the key uncertainty parameters expected to have significant impact on the reservoir development. The range and probability distribution law for each parameter was set considering the uncertainties due to limited measurements or variation in interpretations. A Response Surface Model (RSM) was created to evaluate the uncertainties by using a base dynamic model and applying an appropriate experimental design, which allowed to efficiently study the uncertainty space with a feasible number of simulations. Using the RSM, the primary effects and interaction between parameters were quantified to rank the uncertainties based on their impact on field production.

Key uncertainty parameters were identified including eight OWCs, six fault transmissibilities, horizontal and vertical permeability multipliers, and porosity multiplier. Latin Hypercube was found to be the appropriate Experimental Design for the study considering 17 parameters and the need of building a reliable RSM that includes interactions between them. The design recommended 155 simulation cases, which were prepared and submitted automatically by the software.

Multi-time Responses were analyzed qualitatively to identify the top 5 uncertainties having material impact on field production over 20 years considering 6 existing wells and 30 new well locations. The RSM quantitative evaluation showed three parameters (OWC2, OWC4 and OWC1) having a total effect on the response higher than 10%; followed by PERMX and OWC3 with less than 5%. The other 12 parameters have total effects less than 2%, and the interactions effect is less than 0.5% for any interaction between two parameters. Contrary to the intuition, none of the faults proved impact on the reservoir production.

The results prove very useful to make a right development and appraisal strategy in early life of the reservoir. The new well locations can be ranked and prioritized to optimize the development and effectively appraise the areas with high risks.

Uncertainty assessment has value throughout the life of the reservoir. However, this study indicates that its application in early life of the reservoir can bring immense value. An uncertainty analysis on the reservoir production helps in decision-making regarding the number of wells and their locations to reach a target production by managing the risks.
Challenges in HPHT Well: A Case Study
Authors: Saxena Arpit , Chaudhary Sharad , Adarsh Divyam , Anshul Kumar , Nihalani Dipesh , Tewari Pratush
Published: April 2019

Krishna Godavari Offshore Block has reservoir temperatures of 420 degF and 12,500 psi of bottom hole pressures, field's HPHT rating is a concern moreover other challenges like the wells are complex in terms of depths, profile, high drift, reservoir with heterogeneity, formation pressure variation. The paper discusses challenges during well planning and their execution with adequate methods to successfully drill and case well with less than 15 % NPT.

In harsh environment of KG Basin, HPHT wells encroach on limits of equipment, leaving little margin for error, resulting in increased risk of rapid gas migration, equipment integrity failure, operating limits of tool. The paper discusses use of RSS-Vortex, 200 degC rated MWD tools, NRDPP, modified casing design, reduction in impact of side forces and high torques, optimized bit design, drill pipe cutting tool, reduction of differential sticking to execute the drilling of well within given time. The case study discusses longest 5 7/8" section drilled in an unconventional casing design under HPHT environment in India.

The paper also discusses the unexpected results and observations obtained during execution of program and the lessons learnt from it. Some drilling methods such as first application of RSS-Vortex in a HPHT environment in India has considerably enhanced the ROP by 100% and also significantly reduced casing wear of production casing by 55 %, use of 200 deg C rated MWD tools has increased the robustness of the drilling BHA resulting in minimizing additional BHA trips due to tool failures. The reservoir section drilling has been optimized to 3 bit trips from 9-13 trips done in offset wells. Use of NRDPP's made drilling of high drifted wells easier and maintenance of surface torque within limits had considerably reduced lost production time and ensured safe operation. The improvisation carried out for bit design and casing design has also saved rig days and cost. The new casing design avoids liner tie back which has resulted saving of 7 days of rig time. The use of effective micronized barite OBM system with controlled measures on HTHP fluid loss has maintained good balance between rheology and fluid loss to prevent differential sticking. The downhole tool failure and stick-slip was reduced by 50% by modulating the Variable frequency drive and choosing adequate bit.

These methods and practices require further optimization to enhance the usability. The established methods discussed have created good drilling practices in HPHT environment for KG field and has reduced the drilling NPT levels. Such a huge transformation in reducing the NPT is very significant in HPHT conditions and many of the practices can be standardized for such operations.
Digital Core-New Tool for Petrophysical Evaluation and Enhanced Reservoir Characterization
Authors: Dhar Samir Kumar , Nandipati Viswanath , Bhattacharya Aumeya
Published: April 2019

Digital core generated from micro CT images of rock sample cutting and results obtained from digital core analysis are presented in this work as a substitute of conventional core study for Petrophysical evaluation. Conventional core extraction during drilling, core preservation and analysis are expensive, time consuming processes and often unavailable for small size fields. Moreover, routine and special core analysis results are a critical input for petrophysical characterization. In this situation, digital core study appears to be a cost effective substitute to ensure and validate petrophysical evaluation results.

High resolution 3D micro CT imaging and analysis was done on rock samples cut during drilling or on sidewall core plugs cut by wireline logging tool. Segmented micro CT image slices when combined in 3D space in three orthogonal directions, can be termed as digital core. Solid rock matrix, clay filled and porous rock portions are distinctly separable using micro CT images and their volume fractions can be estimated. Detail textural analysis in terms of Grain and pore throat size distribution of the rock is possible from digital core which controls storage capacity and flow behavior. Two critical petrophysical input parameters for fluid saturation (Sw) estimation are cementation exponent (m) and saturation exponent (n). These parameters are commonly computed from special core analysis (SCAL) on conventional core plugs. But digital core study can provide the estimates of ‘m’ and ‘n’ which replace the need of SCAL.

Digital core study has been carried out in three different reservoirs in west and east coast of India and the results were analyzed. Porosity and permeability data obtained from digital core was first compared with log analysis results and then used to identify different petro physical rock types (PRT). Fluid saturation (Sw) was estimated from resistivity log by using ‘m’ and ‘n’ exponent obtained from digital core seems to be more realistic and corroborates with well test results. Porosity, permeability, water saturation and rock types (PRT) were helped to build geo-cellular model (GCM) for small and marginal reservoir.

Enhanced reservoir characterization by using digital core study result has helped in better understanding and decision making for small and marginal fields where limited well data is available. Finally this leads to the preparation of field development plan (FDP). Digital core technique is less expensive, having quick turnaround time than conventional coring which has translated into high value business impact for any development project.
Petrophysical Characterization of Mineralogically Complex Panna Formation: An Alternate Approach
Authors: Ghosh Arnab , Zacharia Joseph , Majithia Pritpal Singh , Saxena Renu , Nirala Arun Kumar , Narla Sattibabu
Published: April 2019

Panna Formation is a very critical and challenging formation deposited during Paleocene time of geological past in various parts of Western Offshore Basin of India. It was deposited in a fluvio-deltaic environment, sometimes even in a restricted marine set-up. Such variation in depositional setting caused mineralogical complexity, which in-turn imposed a limitation in conventional approach of formation evaluation and saturation determination to identify the pay zones with confidence. A comprehensive approach of integrated formation evaluation for rock quality characterization was attempted using a combination of new generation elemental and acoustic analysis for delineating the potential hydrocarbon bearing zones independent of conventional resistivity-based approach along with a better insight on formation heterogeneity. The studied well was drilled up to Panna Formation and conventional open-hole logs were acquired while drilling. However, due to complex mineralogical nature of the formation, estimation of key critical reservoir parameters was very challenging and imposed higher uncertainties in the results. An alternate approach was adopted using a few advanced log measurements to address this challenge. A combination of new generation elemental and acoustic data has been recorded in a single wireline run after acquiring conventional basic logs while drilling. An accurate porosity was derived by eliminating various mineralogical assemblages along with estimation of a geochemical permeability based on detailed elemental analysis. Measured aluminum from neutron inelastic capture spectrum method enabled to estimate clay volumes with accuracy, which provided the required insight for better effective porosity in such shaly-sand environment. Based on this improved porosity and permeability, an approach for rock-quality indexing was used for reservoir delineation.

Moreover, a good amount of organic carbon was found associated with clays caused shales with higher resistivity. Based on elemental measurements an interesting insight was possible to extract for resistivity independent fluid saturation. An additional pay zone with hydrocarbon saturation based on such resistivity independent approach was possible to identify, which was masked by conventional resistivity-based interpretation. Acoustic analysis results assisted in delineating the zones with possible open fractures to avoid any possibility for unwanted fluid breakthrough.

Based on this approach of alternate integrated petrophysical analysis perforation zones were selected including an additional zone, which was masked based on conventional analysis. The well was started producing around 1,05,000 m3 gas with around 200 barrels of oil per day. This study showcased an alternate and efficient characterization approach for any such mineralogically challenging clastic formations.
Field Operations Strategy for Installing Beam Pumping Units at 660 Wells in Just six Months
Authors: Ali Khan Farhan , Antonio Sierra Tomas , Gabriel Imbrea Robert , Robin Edwards Michael , Al-Rushoud Ali , Al-Abdulhadi Fahad , Shehab Abdulaziz , Al-Ajeel Fatemah
Published: April 2019

Project deliverables included gravel foundation preparation, concrete foundation installation, equipment reception and installation of conventional beam pumping units at 660 production wells in a remote field in Kuwait with a deadline of six months from equipment arrival. Equipment shipments schedules were sequential and therefore an execution strategy was required to successfully meet the project deadline. This paper describes the field operations strategy devised and adopted to successfully meet the deadline.

A temporary operations base was set up at the remote field for coordination, equipment reception, inspection, consolidation, pre-assembly and dispatches.

Operations were divided into six parallel processes as follows: Equipment logisticsGravel foundation preparationsConcrete foundation installationsUnit Pre-assemblyPre-assembled units dispatchesFinal unit installations

Daily output targets were set for each process prior to the commencement of operations. Heavy machinery, manpower and tooling requirements were defined for each process to meet the daily output targets. Progress was monitored daily and subsequently resources were scheduled and utilized to achieve the daily output targets.

Setting up of a temporary operations base at the remote field along with daily coordination of resources resulted in reducing equipment’s offloading, transportation and installation cycle times, which led to increased operational efficiency and reduced logistics and operations costs.

Division of operations into parallel processes helped in tracking the progress of each operation individually, thereby providing over all control in management of operations.

By pre-assembling the beam pumping units at the operations base before dispatching the individual unit, installation time was reduced by 50% when compared to a typical beam pumping unit installation.

Daily output target setting helped in defining the resources required to meet these targets. As the operations progressed, daily monitoring of all processes resulted in identifying opportunities to improvise operations and subsequently the daily targets were revised to increase output for each process without exceeding the resources which resulted in time and cost savings.

Adopting this execution strategy concluded in successful and efficient completion of the project deliverables as follows:Gravel foundation preparations were completed in 133 work daysConcrete foundation installations were completed in 121 work daysBeam pumping unit installations were completed in 103 work days

This field operations strategy for installing conventional beam pumping units at 660 production wells within six months can be considered as a reference for successfully and efficiently completing future large-scale beam pumping unit installation projects at remote locations in a limited time frame.
A Case Study on Enhancement of Separation Capacity at an Offshore Process Complex
Authors: Gupta M K , Sukanandan J N , Singh V K , Pawar A S , Deuri Budhin
Published: April 2019

In one of the offshore complex of ONGC, Carryover of liquid have been observed leading to tripping of gas compressors resulting a loss of significant amount of production. It was established that separation capacity of existing separators even at present operating conditions were not sufficient to process present production. Further an increase of 60% of present gas production is envisaged as per long term production profile. Hence, handling the present and envisaged increased production in the existing separators was explored.

To handle the envisaged enhanced production rate and to avoid carryover issue in existing separators, options such as feed nozzles enhancement and installation of inlet device was explored. Changing feed nozzles is a tedious job, require hot job and longer shut down period and requires complete integrity test of separators as recommended by ASME SEC-VIII, pressure vessel guidelines followed by R-stamping. Therefore modifications in separator internal was suggested which will enhance the separation capacity and can accommodate in the present and envisaged increase of future production.

The analysis revealed that even though the diameter and length of the separators are adequate to handle the load, it was established that the inlet nozzle of the separators are not adequate. Hence, considering many factors such as minimum pressure drop, ensuring good gas distribution, suppression of re-entrainment, momentum reduction and erosion velocity ratio of less than one, modifications in separator internal was suggested which will enhance the separation capacity and can accommodate the present and future envisaged increase of production of more than 60%. It was established in the study that this options of installation of inlet device can be done with minimum modifications and require minimum shutdown period. This option has been recommended and is under field implementation. Hence this work will provide a significant help to oil and gas personal to accommodate higher than design feed quantities in existing separators with minimum modifications and minimum shutdown period.
Middle and Lower Eocene Coals, Cambay Basin and Miocene Coals, South Sumatra Basin: Analogs for Coal and CBM Properties.
Authors: Roy Sandip Kumar
Published: April 2019

This paper attempts to use analogs of coals and Coal bed Methane (CBM) properties in Sedimentary basins to mutual advantage from the knowledge of each other.

An attempt has been made here to showcase as to why two Coal bearing formations, Lower Eocene, Cambay in India and Miocene, South Sumatra, Indonesia can be compared with each other in terms of coal quality and CBM characteristics.

Cambay basin, with an area of 56,000 sq kms is an elongated NNW-SSE rift basin in the western part of India. The basin fill comprises Mesozoic(?) sediments capped by Late Cretaceous Deccan volcanics and a thick tertiary pile of fluvio deltaics. Thick Lignite to sub bituminous coal is found in Middle (two thick seams) and Lower Eocene section (three thick seams of 20-35 m range and one thin seam of 1-10m). Chemically, the Middle Eocene lignite-sub bituminous coal is characteristically low in moisture (4-5%), quite low in ash (1-11%) and high in volatiles (43-55%). The Lower Eocene coals are sub bituminous with 10-20% moisture, low ash(5-10%), low Sulphur(<1%) content. The gas content of the Lower Eocene coals are 6 cubic metre / tonnne, with permeability 1-3 Md with seams slightly over pressured. Depth ranges of both these coal horizons are between1000-1800m approximately.

South Sumatra basin, double in size wrt Cambay basin with an area of 100,000 sq kms, is a NE-SW trending, backarc basin. Series of half grabens punctuated with basement highs, holds Miocene and Eocene Coals in the grabens of a mostly Tertiary sedimentary pile. The Miocene coals (formed in tide dominated coastal plain) are sub bituminous, with VRo 0.4-0.5, low ash(<10%), Moisture(10-18%), high volatile matter of around 40% at depths 300-1000m, with 20-30 seams with gas content of 7 cubic metre / tonne. The Older Eocene Coals are1-10 m thick at depths 1000-2000m formed in peat bogs in fluvial settings.

The Indonesian Coals of Miocene age are very comparable in coal properties and gas content to the Middle and Lower Eocene Coals of Cambay basin and can supplement each other in studies for CBM exploration and exploitation. Of great similarity are the coal quality, ash% and gas content. To take the comparisons further ahead, detailing of thickness, extent, geometry and depositional environments of each of these basins would be advantageous.
Novel Loss Circulation Composition to Treat Moderate to Severe Losses
Authors: Wagle Vikrant , Kalgaonkar Rajendra , AlYami Abdullah , Alanqari Khawlah
Published: April 2019

The novel nanomaterial composition described in this paper has been designed to treat moderate to severe losses. The nanomaterial composition comprises an environmentally friendly nanoparticle based dispersion and a chemical activator. The design is based on a delayed activation chemistry to gel up a nanoparticle based dispersion.

Three different types of nanoparticles were used in the study to develop the novel loss circulation material. Two different types of negatively charged nanoparticle based dispersion and one positively charged nanoparticle based dispersion were used in the study. An inorganic activator has been used for the study. The effect of this inorganic activator on the gelation properties of the nanoparticle based dispersion was investigated. The gelling times were evaluated at different temperatures up to 300°F. The effect of activator concentration on the gelling time of the new composition has also been studied. The effectiveness of the newly developed composition as a loss circulation treatment was also evaluated by performing permeability plugging tests to test the plugging capacity of this novel system.

The novel nanomaterial composition is designed so as to have a controllable gelation time under a variety of downhole conditions to allow accurate placement of the treatment fluid inside the wellbore without premature setting of the fluid. It was shown that the gelation time of the treatment composition could be controlled by adjusting the concentration of the activator. The system is designed so as to give a predictable and controllable pumping time, ranging from a few minutes to several hours at over a wide range of temperatures. This is an important advantage as it allows the loss circulation composition to remain pumpable for sufficient time for placement and develops the network structure that leads to gelation, over a predictable period of time. The set gel, which appears as a crystalline solid, could remain homogenous and stay in place thereby preventing loss circulation.
Establishment of Appropriate Normal Compaction Trend NCT: A Critical Aspect for Reducing Uncertainty in 3D Pore Pressure Modelling.
Authors: Bhardwaj Nitin , Gunasekaran Karthikeyan , Kumar Ashutosh , Dutta Jayanta
Published: April 2019

In 3D Pore Pressure Modelling workflow, establishing appropriate Normal Compaction Trend (NCT) is not only critical but also requires the maximum extent of human interpretation and geological understanding. If not established appropriately, it can introduce substantial uncertainty in the final pore pressure prediction. Though, statistical algorithm techniques are available to establish it, the authors of this paper have demonstrated that establishing NCT manually based on geological logic and regional pressure understanding is much more reliable technique than pure statistical based approach.

In this paper, authors utilizes two different approaches in establishing Normal Compaction Trend (NCT) for the study area. First, based on pure statistical technique and second, a manual one based on combination of 3D velocity trends and regional geological pressure understanding. The 3D pore pressure volumes generated from the above two separate NCT’s are then checked for their conformance and agreement with the regional pressure data and understanding, including validation with post drill measured pressure data in the study area.

The results and analysis in the study area shows that, establishment of NCT based purely on statistical approach results in higher uncertainty in the 3D pore pressure estimation process. Whereas, manual NCT based on logic results in much more robust, reliable, and regionally consistent 3D pore pressure model with lower uncertainty. In our case study, the average uncertainty in the statistical NCT based 3D Pressures was ranging between 0.8 – 2.3 PPG when compared with actual pressures, while in the case of logic based manual NCT the average uncertainty was less than 1.0 PPG.

This case study indicates that in the offshore areas, particularly in areas where there is transition from shelf to slope to deepwater, it is advisable to use all the regional pressure knowledge and geological understanding in establishing the NCT, rather than adopting only the pure statistical methods.
Under Balanced Drilling: Experience in India
Authors: Motghare Prashant , Musale Amol , Desai Amit B. , Parmar Arvindbhai D.
Published: April 2019

Under Balanced Drilling (UBD) pilot project in the Heera and Mumbai High fields of Western offshore India was recently completed successfully. The objective of the project was to establish whether the technology can improve productivity performance in the reservoir section, avoid reservoir damage and thereby enhance oil production from the wells. This paper incorporates the drilling experiences and challenges faced during execution of this pilot project, the well design considerations and methodology, evaluation of the drilling fluid systems and also describes the tangible benefits of using this technology in the drilling of these sections and wells. In terms of the productivity gains from drilling these wells using UBD technology, through the sub-hydrostatic formations offshore Mumbai, the results were very positive. With the success and encouraging results from the pilot project, more wells are now planned, including wells in the losses-prone and depleted Mumbai High and Neelam fields, to incorporate the experiences of the learning curve.
Integrated Solutions to Maximize Asset Value for Mature Field Development: A Case Study
Authors: Abdulkarim Anar , Aki Ahmet , Al Jahwari Mohammed
Published: April 2019

Monitoring and re-evaluation of petrophysical attributes in a mature field under production for many decades is crucial for optimizing production and further development planning. In this case study, a multidisciplinary approach is deployed for formation evaluation and reservoir characterization using logging-while-drilling (LWD) sensors spanning formation volumetrics, fluid analysis, high-resolution image interpretation, and geomechanics to confirm remaining oil saturations and help identify recompletion intervals.

LWD technologies were used in four wells in Sahmah field of Oman to provide an integrated petrophysical and geomechanical field study using a bottomhole assembly (BHA) including gamma ray, resistivity, formation bulk density, thermal neutron, acoustic, high-resolution imaging, and formation pressure testing sensors. A deterministic multimineral petrophysical model was used to derive formation volumetrics and fluid analysis. Geomechanical interpretation used high-resolution microresistivity imaging, acoustic slownesses, and formation pressure data to verify principal stress orientations and to quantify pore pressure and horizontal minimum and maximum stress magnitudes. These data were then correlated with historical data to evaluate sweep efficiency and residual fluid saturations.

LWD sensors have proven to provide robust geological, petrophysical, and geomechanical data compared to previous traditional wireline data acquisition. High-resolution images facilitated fracture evaluation and the determination of the rock facies. Formation pressures were used to fine-tune the geomechanical parameters and depletion profile.

With the integration of historical data, remaining oil saturations were estimated, which enabled new completions intervals. Well test results and the production profiles further facilitated re-evaluation of the original petrophysical cutoffs for the calculation of the oil in place and remaining oil saturations. Reservoir petrophysical attributes were then updated, taking into account the pressure depletion intervals while honoring history matching to help design future well construction and development drilling.

The pilot case study helped better understand the flow units in this mature field and facilitated benchmarking future petrophysical data gathering requirements and optimization of the overall reservoir management strategy, including well-construction options to help minimize field development costs.
Petroleum System Based Integrated Exploration and Prospect Generation
Authors: Dubey Siddharth , Das Debjyoti
Published: April 2019

Identification of a prospect is normally done based on seismic interpretation and geological understanding of the area. However, due to the inherent uncertainties of the data we still observe in many cases that all key petroleum system elements are present, but still the drilled prospect is dry. Such failures are mostly attributed to a lack of understanding of seal capacity, reservoir heterogeneity, source rock presence and maturation, hydrocarbon migration, and relative timing of these processes. The workflow described in this paper aims to improve discovery success rates by deploying a more rigorous and structured approach. It is guided by the play-based exploration risk assessment process. The starting point is always that the process is guided by the the basic understanding of a mature kitchen should always be based on a regional scale petroleum systems model. However, while evaluating prospects, the migration and entrapment component of a prospect should always be investigated by means of a locally refined grid-based petroleum system model. The uniquepart of this approach is the construction of a high-resolution static model covering the prospects, which is built by using available well data, seismo-geological trends and attributes to capture reservoir potential. Additional inputs such as fault seal analysis also helps to understand prospect scale migration and associated geological risks. In the regional play and local prospect-scale petroleum system models, geological and geophysical inputs are utilized to create the uncertainty distribution for each input parameter which is required for assessing the success case volume of identified prospects. The evaluated risk is combined with the volumetric uncertainty in a probabilistic way to derive the risked volumetrics. It is further translated into an economic evaluation of the prospect by integrating inputs like estimated production profiles, appropriate fiscal models, HC price decks, etc. This enables the economic viability of the prospects to be assessed, resulting in a portfolio with proper ranking to build a decision-tree leading to execution and operations in ensuing drilling campaigns.