bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Successful Water Shut Off Treatment in Gas Well of Bassein Field by Polymeric Gel System
Authors: Mattey Padmaja , Varshney Meenu , Daksh Pd. Vikrant , Kumar Aditya 
Published: April 2017

Abstract
Worldwide excessive water production in gas reservoirs has always been regarded as one of the most formidable problems, which hampers the productivity of the well to any extent and in the extreme cases may lead to ceasure of the well due to water loading although the reservoir contains sufficient amount of recoverable reserves. The source of water production can be a channel behind casing due to poor cementation, casing leaks, coning, encroachment, water breakthrough and flow through natural and induced fractures. In the process of shutting off /mitigation of unwanted water production, the identification of source of water inflow in the well is the most important step for choosing a correct technique. However, the problem becomes even more complex if multiple mechanisms of water invasion are simultaneously active in the well.
There are various mechanical and chemical techniques to deal with excessive water production. The mechanical means provide a seal in the near-wellbore openings. However, most of the time, it is desirable to achieve matrix or small fissure penetration of the sealing material. Among the chemical methods, polymer gels are considered as one of the most commonly applied technique on account of relatively low cost, ease of pumping and ability to penetrate deeper into the reservoir.
Bassein is a major gas field in the western offshore basin of India and is producing gas since 1988. The entire structure of the field is a gas cap gas reservoir, which is underlain by very thin oil column and large aquifer and producing gas under partial aquifer drive. The field recovery has crossed 60% of GIIP and presently most of the wells of BC and BE platforms are either producing large amount of water or have ceased to flow due to water loading leading to huge loss of well productivity and making them suitable candidates for water-shut-off treatments. The well BC-2, which was/ had ceased to flow due to water loading, but could not be brought back on production even after mechanical water shut off method was chosen as a pilot well for treatment with deep penetrating high temperature resistant gel system. After gel treatment, the well was put on sustained production along with reduction in water production by 90%.
This paper discusses the laboratory studies for polymeric gel optimization, methodology of job design with operation sequence and results obtained from the field.
Multistage Up-Dip Well (&gt;94 Deg) Fracturing using Plug & Perf Technology through Coiled Tubing - A Case Study
Authors: Gupta Anand , Gupta Vaibhav , Okeke Ugochukwu , Jerath Shweta 
Published: April 2017

Abstract
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.
Exploiting the Thick Tight Gas Sandstone Formation of Periyakudi Field of India through Fracturing Stimulation - A Challenging Experience
Authors: Mahawar Dheeraj , Kumar Rajesh , Das Santanu , Rajendra K , Nainwal S P 
Published: April 2017

Abstract
This paper discusses the Hydraulic Fracturing (HF) treatment of the Andimadam Sandstone formation of Periyakudi field of India. The Andimadam sandstone is a hydrocarbon bearing formation, with estimated in-place reserves of 47.43 MMt (O+OEG) which was prognosticated after drilling and established hydrocarbon potential. Well PD#A was drilled in Andimadam Sandstone and HF in this well was attempted in order to develop and exploit the full potential of the oil and gas reserves of the field.
The fracturing treatment of the tight gas reservoir in one of the deep well in Periyakudi field was performed eld. It was a challenge to carry out HF in well PD#A at such deeper depth formation. There was no previous information available to understand the formation and to predict its behaviour during HF treatment.
HF treatment in tight gas Sandstone laid so many challenges. Formation breakdown, succeeding minimum rate required for fracturing and attaining high proppant concentration during job with crosslinking gel under extremely strenuous operational conditions and pressure limitations were some of the major challenges. Delayed cross-linked gel was used to minimize tubing friction pressure. Managing the pumping rate with pressure limitations during HF treatment was one of the major challenges. Execution of the treatment with low pumping rate results in stimulation of small volume of rock comparatively. All these limitations were overcomed by proper job designing, optimization of fracturing fluid and analysis of pre-frac treatments. A substantial amount of fracturing fluid and proppant placed into the formation maintaining all safety standards. Satisfactory flow back of frac fluid with gas was observed and high flow back pressure at surface was noted.
This paper discusses challenges to execute hydraulic fracturing treatment in well PD#A and the lessons learned during the execution. In addition, it was the deep well (drilled upto 4945 m) in Periyakudi field with low permeability reservoir. Post analysis of pre-frac treatments done to obtain the reservoir properties and to design the main frac treatment. The results of fracturing treatment are also discussed. The promising hydrocarbon potential of the Andimadam sandstone which are based on post fracturing analysis, encourages further future development of the Periyakudi field, Cauvery Basin, India.
Pressure Build up Study with Echo Meter Data - A Case Study of NE Field
Authors: Kumar Vineet , Vema Saurabh Kumar , Bhatnagar Anil Kumar 
Published: April 2017

Abstract
The NE field is located in Barmer Basin, Rajasthan, India. The field is on production with two wells since March 2015 and is currently producing about 1100 bopd. Both the wells are completed with progressive cavity pumps (PCPs). Production is being carried through a small production facility (QPF). The presence of pumps in the well makes the acquisition of pressure build up (PBU) data complex. However, gathering a PBU was considered an important part of gauging reservoir performance. This paper details how an echo-meter was used in one of the wells for acquiring Pressure Build Up data. The echo-meter was used to measure dynamic fluid levels in the casing-tubing annulus; these were used to estimate reservoir pressure and other properties in a cost effective manner. The paper discusses a systematic approach in echo-meter based well test design, execution challenges and the PTA of the acquired data.
The well was flowing with a drawdown of about 100 psi and the liquid level in the annulus was about 100m from the top. The direct collection of PBU data would have required a work-over to remove the pump to place the gauge. This would need to be repeated to retrieve the gauge. A novel & cost effective approach was required to acquire pressure build up data. An alternate option was acquiring the pressure data indirectly by measuring the continuous dynamic level in the annulus using an echo-meter. Although this option had its own challenges, it was economically justified. The required number of echo-meter shots and frequency of the shots was selected based on well test design. The test design provided guidance on the pressure build up rate required for damaged (skin) and non-damaged conditions, permitting us to identify the pressure build up duration and the optimum frequency of the echometer shots. One challenge was concern over annulus liquid level rise in the wellbore. This was addressed prior to the build-up by injecting nitrogen into the annulus to reduce the liquid level in the annulus. This mitigated the possibility of liquid level rise in the annulus to the wellhead.
The quality of the pressure data acquired through echometer shots was good enough for carrying out pressure transient analysis. The pressure derivative plot was constructed and information on skin & permeability was obtained. Radial flow signature was clearly observed. The average reservoir pressure value as well as the permeability agreed with expectations. The impact of uncertainties on the final interpretation was evaluated and found to be in acceptable range.
In current oil price environment and in marginal fields like NE, where there is always a constraint on economics, this low cost technique can be a vital tool for effective reservoir management.
A More Holistic Approach to Determine Economics of Using Synthetic Oil Based Mud over Water Based Mud System in Onshore Development Drilling
Authors: Sinha Pankaj , Kumar Varun , Prabhakaran Tushar , Katre Anurag , Patel Maulik , Doodraj Sunil 
Published: April 2017

Abstract
This paper presents a more holistic approach to compare the drilling economics of Synthetic Oil Based Mud (SOBM or SBM) versus Water Based Mud (WBM) in onshore development drilling in India. Here, a key parameter which has been incorporated in the economics is the mud re-use and overall consumption trend of SBM versus WBM, which has been analyzed from statistical data across 200+ wells and quantified into overall cost savings with SBM estimated across roughly 500 development wells drilled.
The surface holes in all the development wells were drilled with WBM instead of SBM to avoid contamination of shallow water aquifers. Hence, the performance evaluation of SBM was limited to intermediate and production holes only, which were drilled with SBM. Also, past exploration and appraisal wells had used WBM for drilling these hole sections. A key parameter calculated from statistical data was average mud consumption (barrels per meter drilled) for SBM and WBM. The mud consumption of SBM and WBM is expected to differ because theoretically SBM can be re-used across greater number of wells compared to WBM. The average mud consumption was separately calculated for different hole sizes to better analyze the effect of hole size on mud consumption. The actual cost incurred with SBM application in development wells was calculated. Next, cost for drilling these wells with WBM was estimated using mud consumption (barrel per meter) data obtained from exploration/development wells. These two cost scenarios were compared to arrive at the net cost savings with SBM compared to WBM.
A maximum cost savings upto ~10 MMUSD (for various sensitivities especially SBM cost per barrel) is estimated across 500 wells in spite of the higher contracted costs of SBM (cost per barrel) when compared to WBM. The maximum cost saving of ~10 MMUSD corresponds to anticipated reduction in base oil cost in the current crude market. The savings with SBM are mainly attributed to the fact that SBM can be theoretically re-used infinitely moving from one well to the other while the WBM can be re-used for a limited number of wells. This cost model excludes any savings on part of SBM due to improved hole conditions and resultant reduction in drilling non-productive time.
SBM system minimizes drilling problems due to good clay inhibition, enhanced hole cleaning, lubricity additionally SBM is least effected by contamination. However, the higher cost per barrel of SBM and associated environmental concerns normally act as deterrents for operators to choose SBM for planning their wells. This paper provides clarity on the perception "SBM is costlier to WBM" and reinforces the recommendation to use SBM for drilling operations from an overall cost perspective.
A New Approach for Productivity Enhancement in Mature Sand Prone Fields Having Nearby Water Contact Through Slick Water FracPack: A Case Study
Authors: Mishra Nirmal Kumar , Singh Amar , Rakundal Snehal , Rajendra KWS , Nainwal S. P. 
Published: April 2017

Abstract
Due to nearby water contact, conventionally cased hole gravel pack (CHGP) was preferred completion techniques for sand prone reservoirs in western onshore basin and KG basin of India. However, these completions had often performed poorly both in terms of productivity and longevity. This paper describes the detailed case studies for new completion approach (i.e. Slick Water Frac Packing) adopted to alleviate the productivity decline including favourable modification in completion procedure & job treatment.
Since inception, Cased-hole Frac Packing (CHFP) was avoided owing to incompetent shale barriers and nearby water contact. Later on, Horizontal Open-hole gravel packing and Standalone screen completion techniques were adopted but result was not encouraging. The productivity decline was further aggravated with "water-shut off" treatment prior to cased-hole gravel packing.
The existing completion strategy was reviewed to identify the shortcomings & a new completion strategy of Slick Water Frac packing(SWFP) adopted for these fields, which was further customized to suit the specific well conditions. When these customized SWFP were implemented, significant improvement in well performance was seen, in form of hydrocarbon production.
Till date more than thirty wells have been completed with SWFP. Among them, many wells were already producing water beyond the acceptable limit while some wells have very near water contact (&lt; 2.5 m) without competent barriers. Apart from this, one well had long history of fines production and CHGP / standalone screen (SAS) completion applied did not give good result. The execution of customized SWFP was successful in almost all wells and amount of proppant placed in the formation was the range of 300-1000 lbm /feet of perforation.
These completions have achieved the objective of productivity enhancement with average incremental oil gain of about 22 barrel per well apart from formation sand retention.
Although some SPE papers have described the CHFP application in wells having near water contact, but the combination of WSO treatment and Frac packing treatment for wells already producing high water cut, is unprecedented as per author's knowledge. The information provided in this paper can be used to enhance hydrocarbon production without increasing significant water production in similar fields.
Optimizing Cost and Effectiveness of Well Interventions: An Holistic Approach
Authors: Gosain Sonali , Dhiman Mansi , Kothiyal Manish Dutt , Upadhyaya Akhilesh , Jetley Shailendra , Jain Sachin , Jain Akanksha , Patel Nilay , Hammond Paul 
Published: April 2017

Abstract
Cairn India Limited operates over 600 wells in the Barmer basin in Rajasthan with over 30 well intervention (rig and rigless) units deployed on an average to perform over 5000 interventions per year. Maintaining the quality of interventions and analyzing the performance of such a scale of operations is a major challenge. This paper describes "An holistic approach" for evaluating well intervention campaigns, reviewing candidate selection, intervention techniques and technologies utilizing an intensive data warehouse and the techno-economical tool, "Scorpion Plot" to optimize intervention costs and rewards.
The performance of all Well & Reservoir Management (WRM) activities are analyzed in terms of cost and associated gain. The data gathered is categorized into four types namely Well Surveillance, Production Enhancement, Restoration, Well Integrity and Support. The expenditure on non-oil and gas gain generating interventions (Well Surveillance, Restoration, Well Integrity & Support) plotted on cumulative cost basis gave an overall idea of the health of the well stock and understanding of the value of information from data gathering. The Production Enhancement activities, sorted in increasing order of cost per barrel gained were plotted on a cumulative cost vs cumulative gain curve termed as "Scorpion Plot" because the shape always largely resembles a "scorpion tail" with low cost-high gain jobs lying in the bottom left part of curve and high cost and negative value interventions forming the "tail" of the scorpion to the top right. The analysis of the type of jobs falling in the different tranches of the plot on the basis of $ spent per barrel gained, helps in identifying the areas for optimizing the process of candidate selection and job execution.
The objective is to remove negative gain and reduce high cost low gain activities (the tail of the "scorpion plot") and shift the curve towards the bottom left to improve oil realization while reducing cost. After Action Reviews are carried out for all the negative and lower value activities and the lessons learnt are fed back into the intervention management system to enhance future intervention campaign results. Production enhancement activities such as ‘Well Stimulation’ positioned in the negative value group were further analyzed based on the selection criteria, technique of stimulation, chemical recipes/volumes were benchmarked against the high value interventions. Case studies showing how the analysis helped in better candidate selection and best technique for interventions are discussed.
This paper also describes how the process of candidate selection, cost, resource allocation and job impact assessment is automated ensuring engineering focus on job planning and after action review.
Characterisation and Modelling of Fractured Basement Reservoirs: A Case Study
Authors: Nautiyal D. K. , Goswami Sandeep , Dutt Ankit 
Published: April 2017

Abstract
Padra field, discovered in 1977, is located in the eastern margin of Ankleshwar-Broach tectonic block of Cambay basin. Padra basement is overlain by thick sedimentary succession of clastic reservoir rocks and shale barriers including Cambay shale (major source rock). The characterization, modelling and flow simulation of fractured basements is complex and entirely different from conventional reservoirs. The paper aims to introduce a unique approach for study of basement reservoirs.
A Discrete Fracture Network (DFN) model is made to represent two fracture set explicitly, based on spatial and non-spatial parameters. Fracture orientation is distributed using statistical model of Fisher. Simulation exercises are carried out wherein; fractures are not explicitly represented but an equivalent virtual medium is created with effective properties (porosity and permeability) representing the dynamic properties of the flowing domain (fractures). Being a type I basement reservoirs, single medium model (single porosity and permeability) is used for flow simulation with effective properties calculated by Oda's method of numerical flow.
This work paves the way to establish workflows that benefit from the merits of complementary methods, which will allow us to characterise the uncertainty in naturally fractured reservoirs more accurately. The case study elucidates the experiences gathered during simulation study of 112 wells, out of which 48 wells have been found to be hydrocarbon bearing. Pressure and water cut trend indicate active aquifer support. Early cessation of structurally higher wells in same as well as different fault blocks has been found to be a prominent anomaly. Also, strong contrast in reservoir performance of nearby wells has been found in a few cases. This indicates a great level of heterogeneity in fracture distribution in reservoir. Ten zones of alternate high and low fracture intensity have been created based on interpretation of 6 FMI logs. The fracture counts (P10, count per length) in wells with FMI should have been used as indicator for fracture intensity (fractures area in a unit volume). Sensitivities on interaction forces and roughness of fracture planes is carried out as a key part of dynamic modeling. The DFN approach allows us to generate multiple realisations of fracture models and condition these to the field observations.
Characterizing fractured reservoirs using borehole core and image logs provides the static description of fracture properties. However, some fracture properties (3D fracture-density) are highly uncertain when they are evaluated using static characterization methods only. Hence, dynamic calibration methods are required to condition geological fracture models and to increase confidence in the adopted conceptual model. Pressure transient analysis integrated with log/core information must be used to characterize the reservoir's flow capacity and for the dynamic calibration.