Deposition of paraffins and asphaltenes in the near well bore region has always been one of the most studied cause of production decline especially in brown fields. Pumping heated fluids, inhibitor pumping, or mechanical methods of clean out using coiled tubing jetting or jointed pipes are some of the industry prevalent methods of countering this issue. But these methods are both cost and time consuming with short lasting results. With industry constantly marching towards the production of more and more ‘difficult oil’ it has become the need of hour to devise and deploy more cost and time efficient methods to mitigate the problem. The paper highlights the application of In-Situ Heat generation methodology and details the execution process used to mitigate the near wellbore wax deposition in field X in western part of India. Field X in India has been developed as an onshore field wherein wells are drilled in shallow reservoir. To support the oil production, some wells are produced using Artificial Lift techniques like PCP. Crude of the reservoir is high in wax content with pour point at 60 °C which is very close to reservoir temperature (~65 °C) resulting in high wax deposition against screens & near wellbore. The wax dissolution temperature is well above the reservoir temperature, due to which any effective remedial treatment necessitates higher temperature generation for dissolution/inhibition of wax problems. In-Situ Heat generation methodology is based on the concept of down-hole heat generation by exothermic chemical reactions. The paper details the operational challenges observed while conducting the operation in both PCP and non-PCP wells and various measures taken to mitigate the same. Steps in developing this system and using it in the field are documented, and the challenges encountered, lessons learnt and recommendations for future application of the system are described.
Organic deposits such as paraffin and asphaltene in the near-wellbore region are common damage mechanisms in oil wells, especially in brown fields, and account for major production losses from these fields. Typical efforts to mitigate these problems include pumping of several types of remedial treatments to inhibit or dissolve deposits, pump heated fluids as in hot oil treatments, or use mechanical methods such as cleanouts with jointed pipes and coiled tubing. Most of these methods are not time and cost-efficient for two reasons. First, such treatments are usually not one-time solutions but are required at periodic intervals depending on the severity of the problem. Second, the specific requirements such as long soaking time, exotic chemical systems, large equipment footprints, safety etc., often add to the associated service costs.In some of the fields being developed in the western onshore fields of India, heavy organic deposition across screens and in the near-wellbore region is being experienced. This is suspected to be occurring due to wax appearance temperature being close to the reservoir temperature. The wax dissolution temperature is well above the reservoir temperature, due to which any effective remedial treatment necessitates higher temperature generation for dissolution/inhibition of wax problems. Different types of solvents have been used for remediation purposes and have yielded mixed result.The concept of heat generation by exothermic chemical reactions has also been applied in the field after taking a cue from oil industry application, pipeline pigging industry to tackle the similar problems. On lines of this concept, the authors designed an effective and cost-efficient in-situ heat generation treatment to be applied in oil wells for removal of organic deposits. After laboratory testing using a range of products, the regulated components from the pipeline systems were replaced with safer, non-regulated products to suit oil well treatment. A successful field trial was achieved with the chemicals in generating heat to attain temperatures beyond the wax dissolution temperature, resulting in increased production. This paper documents the steps in developing this system and using it in the field, and aims to describe the challenges encountered, lessons learnt and recommendations for future application of the system.
Field X in Rajasthan, India has been developed with 22 Injectors wells & 40 Producers wells. Most of the producers are completed with standalone screens of different types like conventional, ICD's and SSD types. Almost 60% of the producers are completed with ICD type screens. The open hole for screens section has been drilled with 10.2 ppg SBDIF (Synthetic based drilling fluid) which includes dolomite and barite as weighting agents. After running the screens, the screen section is displaced with 8.4 ppg low weight SBDIF (Synthetic based Drill-In Fluid) which has organophilic clay (Viscosifier) and emulsifier as the key components. Due to some operational delay in bringing the wells online, mud was left inside the screens for a few months. The deposition of mud filter cake and heavier hydrocarbon probably choked the ICD screens ensuing a number of ICD's non-contributing. Conventional stimulation techniques didn't help in achieving good results.To effectively remove the suspected damage a coiled tubing based solution was implemented which involved the application of Inflatable Straddle Packer tool. It provides pinpoint accuracy for conventional, horizontal and multilateral stimulation treatments. Coiled Tubing Conveyed Re-Settable selective straddle packer elements allow multiple settings in one trip. Treatment Valve allows precise injection of treatment fluid & adjustable element spacing helps in straddling the long interval.A case history of successful application of CT conveyed inflatable straddle apcker tool in field X in India is presented in this paper which enabled the correct placement of a series of stimulating chemicals targeting different damage mechanisms i.e. wax deposition, mud filter cake, inorganic scaling etc. Post stimulation production logs showed excellent improvement of conformance in zonal contributions.The learning from this stimulation technique was also applied to the horizontal wells in field Y with very encouraging results. Introduction:Field X & field Y lie within a narrow rift basin formed during the Palaeocene epoch. The Oil is contained in the Z group sandstones consisting of approximately 250 m of medium to thick bedded fine to coarse grained sandstones interbedded with mudstones. The sands were deposited in a variety of braided to sinuous meandering channels and are composed almost entirely of mature quartz grains. The Z group has been subdivided into five units on a lithostratigraphic basis. At X field, they are designated ZX1 to ZX5 & at Y field, they are designated as ZY1 to ZY5. The lower part of the Z formation is dominated by well-connected sheet flood and braided channel sands, whilst the Upper Z formation is dominated by more sinuous, laterally migrating fluvial channel sands.The fields contain excellent reservoir quality sands with porosities of 18 to 33 % (average 25%) and permeabilities of upto 20 darcies (average 5 darcies). The fields contain waxy sweet crude oil with API gravity ranging from 20ºAPI near the OWC to 30ºAPI higher in the oil column (average ~27ºAPI). The ...
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.
Aishwariya Barmer Hill (ABH) field area consists of a laminated high porosity (25-35%), low permeability (~1 mD) unit of 50-250 meters thick hydrocarbon bearing payzone. With the success of the first 6 pilot wells, it was decided to extend to the whole field with more than 44 horizontal wells. The horizontal wells are ~2300-2600 mMD long, lateral average length of 1000m and multistage hydraulic fracturing (10-17). These wells face numerous complications due to high gas-oil ratio, sand production, and corrosion tendencies because of high CO2 mole percent concentration (40-60%) in fluid. Further complications include downhole pumps setting at very high deviation (60-65 deg), rod failures-wear in high deviation wells, rod rotation due to deviation and gradual productivity declines due to sand deposition at lower side of downhole completion. Due to low permeability and low mobility fluid nature, it was necessary to find efficient ways to enhance the overall hydrocarbon recovery factor of the field. Several sensitivities were performed, on the number of wells, number of hydraulic fractures, well design, artificial lift options, water, and gas injection. According to the sensitivities results, the best developed scenario envisages high number of multiple frac wells to increase the recovery factor. Based on the detailed evaluation of available artificial lift options, SRP was selected over Jet pumps as the most suitable artificial lift considering the requirement of large drawdowns & operating costs of lifts. The risk of gas issues was mitigated by keeping the tubing-production casing annulus vented and further alleviated by running suitable downhole gas separators. Other problems were analyzed, and multiple attempts of solution implementation were done. This paper addresses an inhouse ways to tackle sand, high gas rate issues, along with rectifications &learning of other problems faced during the last 3 years of field operations, including digitalization projects for visualization of well behavior. This paper also addresses a few remarkable calculated parameters which are - actual production loss calculations whenever well is shut-in (considering wellbore column storage effects), calculated gas free liquid level pump submergence and pump intake pressure from pump load live data. The purpose of this paper is to describe technical & operational challenges along with lessons learnt/solutions implemented in last 3 years.
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