bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modelling and Implementation of Dual Artificial Lift System for Production Enhancement: A Successful Case Study of Aishwariya Field
Authors: Khare Sameer , Baid Rahul , Prusty Jyotsna , Agrawal Nitesh , Gupta Abhishek Kumar 
Published: April 2019

Abstract
The objective of the paper is to present the methodology adopted for dual artificial system modeling in Aishwariya field– an onshore oil field located in prolific Barmer Basin, India. This paper presents a conceptual and feasibility study of combination of Jet pump (JP) and Electrical Submersible Pump (ESP) together as means of artificial lift for production enhancement in a well. It discusses the workflow to model a well producing on dual artificial lift (ESP producing in combination with Jet-Pump) via industry standard software and demonstrates the same with a successful case study.
Requirement of ESP change outs to restore/enhance well production in cases such as undersized pumps, pump head degradation requires an expensive work-over. However, an option for secondary additional lift (JP) installation along with primary lift (ESP) in completion system can eliminate the costly wok-over requirement if both lifts can operate simultaneously.
The procedure to model the dual artificial lift (JP and ESP) has two major components: a) Psuedo IPR at ESP discharge node and b) Standard JP modeling using pseudo IPR. Pseudo IPR is generated by modifying well specific IPR using ESP pump curve for a specific frequency. The down-hole ESP pump intake & discharge pressure sensors help calibrate the model accurately for further prediction.
The existing completion in the Aishwariya field is ESP completion with the option of JP installation in cases of ESP failures as contingency. Moreover, jet pump can be installed using slick line with minimum well downtime (∼ 6 hrs). Therefore, installing and operating the Jet pump above a running ESP will not only increase the drawdown but will result in production enhancement with minimal cost.
Novel Technique: No standard industry software can help model such dual lift systems with ease. The in-house developed workflow allows engineers to successfully model such complex lift scenario for routine production optimization and well surveillance activities.
Integrated Loss Control and Prevention Technologies for Complex Deep Wells Based on Precise MPD
Authors: Wang Gang , Fan Honghai , Zhang Wei , Yang Yang , Han Zili , Wu Hongxuan , Li Wanjun , Li Jiaying , Zhou Tuo , Zhou Haiqiu , Liu Jitong 
Published: April 2019

Abstract
M15 well contains complex intervals, where anticlinal structures developed from faults make long mudstone barriers full of cracks, which makes it hard to predict pore pressure. Loss is one of the most serious problems during drilling and cementing, while blow out accidents happen sometimes. Previous casing programs hardly adjust to all complex intervals and conventional LCMs (loss control materials) play few roles. As a result, designated targets used to be rarely reached.
It is proved that low pressure intervals shall be isolated firmly and complex intervals as well as reservoirs should be developed in independent intervals, thus casing programs have been modified. 188 lab tests were finalized, including 180°C hot rolling, anti-contamination test, lubricity test and inhibition experiments, in order to develop a kind of organic salt mud system that has premium inhibition, plugging, lubricating, heat & salt resistance properties. Precise MPD (managed pressure drilling) techniques are recommended to achieve near-balance drilling operation, solving borehole instability problems to some extent.
In the second interval the organic salt mud system is applied, while logging and casing running may be accomplished in one time. Besides, strings can be tripped out smoothly and high pressure brine productive zones are drilled safely. φ339.7mm casing joints are set at the depth of 3848m in the second interval and φ244.5mm casing joints are set at the depth of 5177m in the third interval, in order that deeper complex formation may be developed in a separate casing interval in which precise MPD is applied with LCMs while drilling and compound plugging agents. Therefore, downhole pressure is precisely controlled and large cracks are plugged statically on 28 occasions. Designated targets have been all reached and 20 oil & gas productive layers have been developed.
Downhole complexities arising from loss and blowout have been solved in M15, where φ339.7mm casing was set at the deepest interval in CNPC overseas operation history, making a new record of safe drilling operation, borehole quality and cementing quality. More oil and gas productive zones have been discovered and all designated targets have been achieved. New drilling experience got from M15 has significant meanings in the development of similar blocks.
Petrophysical Evaluation of Gas Hydrates : Estimation of Hydrate Saturation, Krishna Godavari Basin, India
Authors: Baruah Promothes , Vangala Sampath Rao , K Murali 
Published: April 2019

Abstract
The Natural Gas Hydrate Program Expedition (NGHP) has been formed to explore and develop the gas hydrate resources of Indian subcontinent in three stages. The first stage was to identify the presence of gas hydrate deposits in Indian Offshore Basins and the second stage was to identify gas hydrate in sand rich geological setting within gas hydrate stability zone and suitable locations for production testing. During the second stage, 42 gas hydrate wells at 25 sites were completed in deep water areas of Krishna Godavari and Mahanadi offshore in Eastern Coast of India.
This paper provides an insight into formation evaluation techniques as effective tools of evaluating gas hydrate saturation. During the second stage of the expedition; LWD, wireline well log data and pressure cores were acquired and they have been used for estimation and validation of gas hydrate saturations. The gas hydrate saturation have been estimated by three methods viz., standard deterministic Archie method, probabilistic method using ELANPlus model and Density Magnetic Resonance (DMR) technique. This paper also emphasizes the estimation of gas hydrate saturation considering gas hydrate as a part of matrix in the ELANPlus model and validation with pressure core results.
In Petrophysical model, hydrate can be considered either as a pore-filling hydrocarbon (fluid) or as a matrix mineral (rock constituent). When it is assigned as a pore-filling hydrocarbon, the model calculates the matrix volumes & porosity and calculates the water saturation in the same way as the basic interpretation model. When the hydrate is considered as a constituent of the matrix in the model, hydrate volume is calculated and the hydrate saturation is then arrived at by dividing this volume by the total porosity.
Hydrate is invisible to Nuclear Magnetic Resonance (NMR) measurements. In DMR technique, the deficit in NMR porosity as compared to Density porosity is used to estimate the hydrate volume accurately.
Gas hydrate saturation estimation in one of the well drilled during the second stage of the expedition from Krishna Godavari basin is discussed in detail in this paper. Gas hydrate saturation estimated from DMR method is found to be close agreement with other methods such as deterministic Archie and ELANPlus based probabilistic methods. The gas hydrate saturation is found to be in the range of 20-60% in the considered well. The results have been validated with gas hydrate saturation obtained from pressure cores retrieved from the nearby core hole.
The present approach is to estimate gas hydrate saturation with different methods and validation with pressure core data to minimize uncertainty in estimation of petrophysical parameters for such type of unconventional reservoirs.
Integrated Reserves Management Using Portfolio Approach: A Case Study
Authors: Al-Bahar M. , Al-Sane A. , Bora A. , Kumar A. , Mendjoge A. , Dhote P. , Antonevich Y. , Back M. , Kassim A. , Mason D. , Sethi M. U. , Siddique E. 
Published: April 2019

Abstract
Management of oil and gas resources and reserves has always been complex process as the company’s portfolio consists of resource and reserves volumes with varying degrees of uncertainty and maturity levels of projects. Some of the hydrocarbon volumes are from resources that are highly uncertain and require technology imprevoments or breakthroughs. However, for strategy formulation of the country/company needs consideration of all hydrocarbon volumes that can generate value in the future. The prioritization of development strategies for its reservoirs based on rigorous technical and economic assessments while protecting the national interests is a challenging task.
Kuwait Oil Company (KOC) has been using multiple systems for both asset and business planning processes that is not optimized for faster turnaround. The proposed integrated and automated reserves management solution provided a structured environment for systematic economic evaluation and portfolio optimization. It facilitates the visualization of key reservoir parameters delivering full understanding of the forecasted reserves, production and economic potential of the entire company. It indentifies gaps between reserves and detailed development plans based on technical and commercial criteria. By Optimizing the project timing and economics results in reduction of budgetary expences, increase in portfolio revenue and greater confidence for the company. Ranking the investment opportunities helps in allocating resources appropriately amongst different projects in a systemic manner to ensure profitability of the company. This approach provides ease to KOC in modeling complex scenarios and quickly evaluate a wide range of different development strategies catering for risk and uncertainty
This paper describes current industry challenges in resource and reservoir management, and an integrated approach to reserves, economics and portfolio management envisioned for Kuwait Oil Company (KOC) which will assist in identifying optimal reservoir development options to meet any defined strategic goals. The results and benefits gained after deployment of pilot will also be explained in the paper. This integrated approach for optimization of Asset Action Plans is a unique solution and would prove beneficial for our industry.
Extending the Curve – Drilling Medium Radius Horizontal Well in Low Cost Environment
Authors: Baheti Murli Manohar , Sinha Pankaj , Prabhakaran Tushar , Paliwal Kunal , Sharma Anurag , Doodraj Sunil , Vermani Sanjeev 
Published: April 2019

Abstract
The paper presents a case study on adopting an economics driven novel approach to directional well planning and drilling a horizontal well in a single well FDP (field development plan) for a marginal field in onshore India. The paper highlights the successful drilling of 8-1/2″ landing production section with DLS &gt; 7 deg/30m followed by the 8-1/2″ horizontal lateral. The feasibility of achieving high DLS well trajectory using basic directional tools and associated hole problems with their mitigations are addressed in the paper.
Low crude price resulted in marginal economics for the above FDP. To improve economics, the capital expenditure had to be minimized (by utilizing existing well pads and production facilities) and maximize oil production (by drilling horizontal wells). Hence, constrained surface locations and fixed subsurface targets resulted in complex well trajectory (DLS&gt;7). The Trajectory was finalized after multiple iterations to ensure that it is meeting requirements of deep set artificial lift, free of collision threats and also meeting the geological objective of placing the well in a thin reservoir with defined GOC and OWC. The final well design included one 12 ¼″ surface section with 9-5/8″ casing and 8-1/2″ production hole with 7″ casing to TD (~1800m MD). The well was initially planned with special RSS tool which could achieve high DLS, but the cost and lead time were the contra-indicators. Hence, the 8-1/2″ hole was planned with two BHAs. The build and land section was planned with motor (1.6 deg bend and rpm limitations) and tricone bit BHA to build from 9 deg to 90 deg inclination with a DLS of 7 deg/30m in 400m closure. The horizontal lateral was planned with RSS BHA and PDC bit including density image LWD for geosteering. To minimize hole sections for cost reduction, the landing and horizontal section was combined in a single hole which increased risk associated with wellbore stability, hole cleaning and casing running. The risks were suitably addressed through in-house geo-mechanics inputs, application of ERD procedures & real time T&D monitoring
With no offset well data (in onshore India) to substantiate the possibility of achieving high DLS trajectory, the motor and tricone bit BHA successfully achieved the desired trajectory with max DLS ~11deg/30m and without any hole problems. The well was successfully landed and placed in the reservoir. The operator gained significant confidence in understanding of drilling high DLS wells without expensive drilling tools
Challenges in Selection and Using of Production Chemicals with CEOR Operations During Polymer Breakthrough Phase
Authors: Zagitov Robert , Venkat Panneer Selvam , Kothandan Ravindranthan , Senthur Sundar , Ramanathan Sabarinathan 
Published: April 2019

Abstract
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 chemicalsPerformance of production chemicals in the presence of polymerSolids loading in production system Emulsion and produced water treatmentSuitability of produced water treatment facilities Revised scaling and fouling control with back produced polymer with rich divalent ions present in produced waterStrategizing chemical management system to suit polymer flood and polymerized back produced water treatment regime
Design and Development of a Novel Fluid Loss Additive for Invert Emulsion Drilling Fluids from a Renewable Raw Material
Authors: Maghrabi Shadaab , Smith Delores , Engel Aaron , Henry Jennifer , Fandel Joseph 
Published: April 2019

Abstract
Commonly used fluid loss additives (FLAs) in today's invert emulsion drilling fluids include materials with various attributes. The unmet needs of existing materials may include: Environmental restrictions due to ecotoxicity or biodegradability concernsPerformance issues at high temperaturesOverdosing at high temperaturesHigh costsFormation damage
To address these challenges, a FLA was developed for invert emulsion drilling fluids that is made from a renewable raw material and performs at high temperature and high pressure. The renewable raw material used to make this novel FLA is a biopolymer byproduct of the paper pulping process, and was chemically modified under controlled conditions to create a high-performing FLA. Detailed testing was done to determine the additive's performance in different base oils (mineral and diesel), at various mud weights (12 to 16 ppg), at elevated temperatures and in different fluid systems characterized by rheology and high-pressure, high-temperature (HPHT) fluid loss. The novel FLA was compared to other commercially available FLAs for fluid loss performance.
The novel FLA outperformed or was on par with the industry available FLAs tested in this study. The novel FLA realized comparable fluid loss performance of less than 10 ml at 375 F at lower concentrations as compared to the industry FLAs. In some cases, the novel FLA performed at higher temperatures, whereas some of the industry available FLAs did not. The novel FLA also boosted the electrical stability (ES) of the emulsion in certain fluid systems. The novel FLA showed minimum change in the rheology of the oil-based fluids as compared to the industry available FLAs. The novel FLA demonstrated reasonable performance in different mud weights, base oils and fluid systems. Since this novel FLA is derived from a renewable raw material, it may have less of an environmental impact compared to other FLAs utilized today.
The novel FLA: Was developed from a renewable raw material for invert emulsion drilling fluids;Performed on par or outperformed industry available FLAs; andBoosted the ES of the emulsion for certain fluid systems.
Investigating Optimized Well Placement in San Andres Tight Oil Dolomite Reservoir by Integrated Reservoir Modeling Approach
Authors: Yang Junjie , Karam Pierre , Cozyris Kristian , Hustak Crystal , Doherty James , Allen Carmen 
Published: April 2019

Abstract
As a well-known tight oil dolomite reservoir in Texas, San Andres formation has attracted broad attention about horizontal drilling and development strategy. To optimize the oil recovery and asset’s economics, the aim of the study was to use an integrated approach to understand reservoir heterogeneity and performance, determine optimal landing zone and its impact on production, understand fracture geometry using different pumping schedules, and the optimal cluster spacing. In addition, the potential benefit of a refrac and infill drilling program was also investigated.
To tackle the optimization problem, an integrated reservoir modeling workflow was developed. Starting with a 1-D geomechanical model which captures the in situ stress profile and rock mechanics, hydraulic fracture modeling was developed to history match the treatment process, and therefore a comprehensive fracture geometry can be estimated. In the interim, a geological model with populated reservoir properties was established based on the offset data including petrophysical logs, imaging logs and cores. After calibration, the dynamic reservoir model was built to test multiple sensitivity runs for an optimized field development strategy.
Geological modeling separated the field into two models to study the variation of properties on the east and west side. The east section shows a higher porosity and lower saturations. Those water saturations increase below the main pay zone indicating a potential water source. In addition, special core analysis shows a strong oil-wet nature of the reservoir rock. In the east section, sensitivity runs included infill development and variations in landing depth. It is noted that the production is not sensitive to landing zone because fracture geometry is primarily controlled by vertical stress profile. In the west section, sensitivity runs included refrac, infill drilling, and a greenfield development plan with variations on well spacing and completion design. The observation shows tighter well spacing or cluster spacing accelerates the oil production in early time, while yielding similar long term oil recovery and shows a combination of refrac and infill drilling yields a 21% incremental oil production beyond the base case.
This study provides valuable information about the workflow to develop tight oil plays by describing a detailed case study. The result also sheds light on the optimized field development strategy for analogous fields.
Does Higher Viscosity Improve Proppant Transport?
Authors: Galindo Tanhee 
Published: April 2019

Abstract
The use of high viscosity friction reducers (HVFR) as alternatives to guar-based fluids to improve proppant transport and lessen formation damage has increased rapidly. While several product options are available, the criteria for selection of a product has focused on viscosity at 300 RPM (511s-1) that meets or exceeds that of linear gel fluids. However, there has been limited data available on what the target viscosity should be, how it influences the fluid's ability to transport sand, and the potential for damage to proppant conductivity. This study presents methodology used to screen HVFR's and results on product performance, which identified a need for alternative specifications to viscosity to achieve maximum performance.
The proppant transport capacity in dynamic conditions was evaluated for twenty-eight commercially available friction reducers and HVFR's in field waters which could have up to 40,000 TDS. A slot flow apparatus was used to mimic fluid flow through a fracture under different shear and flow rate conditions. Viscosity and elasticity measurements were also obtained using an advanced rotational rheometer. For comparison, linear gel and crosslinked guar fluid were also evaluated.
While viscosity at 300 RPM (511s-1) and more recently high viscosity at lower shear rates, have been used for selection of HVFR's, these parameters alone do not indicate proppant carrying capacity. The authors did not find a correlation between higher viscosity and better proppant transport, rather they propose that too high a viscosity can negatively impact transport. The results provided insight into the effect of flow rate on proppant transport, with some HVFR's that exhibited higher viscosities at low shear, losing their transport capacity at the same low shear. Elasticity testing of those same products suggested that HVFR's have a critical elasticity range at which they will provide optimal performance. Polymer residuals were also evaluated on proppant post-test and compared to traditional linear gels and crosslinked fluids. Results suggested potential for damage if HVFR's are used without breakers. Different viscosity targets should be set when selecting a HVFR and coupled with other testing criteria such as elasticity and dynamic proppant transport.
This paper provides insight into the need for development of standardized test criteria for HVFR selection. Further testing and screening of HVFR's will help increase the understanding of key factors influencing sand transport and their effect on proppant pack conductivity.