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Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. The most important measure of the treatment is the productivity of the well after treatment.
Mukku, Vinil (Schlumberger) | Lama, Tshering (Oil India Limited) | Verma, Sanjay (Oil India Limited) | Kumar, Pankaj (Oil India Limited) | Bordeori, Krishna (Schlumberger) | Chatterjee, Chandreyi (Schlumberger) | Kumar, Arvind (Schlumberger) | Mishra, Siddharth (Schlumberger) | Sharma, Lovely (Schlumberger) | Batshas, Siddhanta (Schlumberger) | Shah, Arpit (Schlumberger) | Prasad, C. B. (Oil India Limited) | Pathak, Digantha (Oil India Limited) | Saikia, Partha Protim (Oil India Limited)
Abstract Hydraulic fracturing can establish well productivity in tight and unconventional reservoirs, accelerate production in low- to-medium permeability wells and revamp production in mature wells. However, not all wells are suitable candidates for hydraulic fracturing and the technique can be detrimental if the right candidate is not chosen. An integrated approach is required to select the wells that are the most-suitable candidates for hydraulic fracturing. This paper discusses the hydraulic fracturing candidate selection workflow and execution carried out in the year 2015 to 2016, which has unlocked reservoir production potential of Upper Assam basin fields of Oil India Ltd. (OIL). Wells which showed poor/no inflow prior to hydraulic fracturing operations, exceeded operator expectations during post fracturing production. Better reservoir management through hydraulic fracturing, rejuvenated ceased wells with an incremental oil production rates of 1380 bopd cumulative rate from six wells, post fracturing. The candidate analysis workflow described in this paper, can serve as the best practices guide for any operator investigating workover candidates among multiple fields, with an objective of production enhancement. A customized candidate selection methodology was developed to identify the 10 best candidates from a pool of 70 vertical/deviated wells in two phases of the hydraulic fracturing campaign. In the absence of dynamic reservoir analysis, offset well data analysis assisted in filling the data gaps by enabling geological and reservoir level understanding. Well production models were calibrated with the production history, geo-mechanical models were prepared and used in the fracture modelling to generate optimum fracture geometry and predict post-fracturing production. Wells were ranked according to incremental hydrocarbon production coupled with risk factors including completions integrity. In the execution, fracturing model was validated by performing fracturing diagnostics tests such as Step Rate and Minifrac injection. The final calibrated model was then used to design the optimum fracturing treatment. Given the age of wells and traditional completions architecture, best practices were developed to counter challenges of high pressures and rate limitations in wells with depth greater than 3500 m. As stimulations and well preparation in completed wells are expensive, it was critical to identify the most-suitable candidates with the available dataset before attempting well preparation and further acquisition. This was addressed through a customized workflow to perform production rate transient analysis for reservoir dynamic flow properties, create synthetic geomechanical models for stress profile & fracture vertical growth estimation.
Abstract LEAN concepts have been applied in a wide range of industrial areas to identify and eliminate the waste in every stage of different processes, currently improve efficiency and lower production costs has become popular among Oil and Gas senior-level management. Minimizing waste is the base on which LEAN concepts are built. A LEAN endeavor seeks to eliminate activities or processes that consume resources, add cost or require unproductive time without creating value. The concepts can be described as striving for excellence in operations in which each employee seeks to eliminate waste and participates in the smooth flow of value to the customer. As part of a complete new strategy to ensure permanent improvements within the whole operational environment Petroleum Development Oman (PDO) has applied LEAN on drilling and other corporate core areas. This paper presents a LEAN application to optimize the Snubbing Interventions in order to ensure a significant CAPEX and OPEX reduction in an extensive deliquification campaign for gas wells thru the implementation of high end Velocity String (VS) completions. The projects involve the application of LEAN methodology from the early planning stages using in many cases re-engineering to the functional specifications, material selection and operational procedures. This re-engineering includes a deep review of every intervention activity, the application of new technologies and the analysis of major issues during previous snubbing interventions, followed by the measurement of the real operational times and deep technical brainstorming on every stage of the intervention process. All those factors have contributed with a significant amount of improvements along the intervention campaign.
Abstract To meet increasing gas demands while drawing from the shrinking reserves of a mature field, CTEP (Chevron Thailand E&P) is drilling as many wells as economically feasible. Wells have to be drilled and completed very quickly to minimize rig time and reduce the "per well" drilling cost. In 2005, the average time to drill and complete a slimhole well was 6 days; the target for 2006 is 4.5 days. During 2005, CTEP drilled and completed over 300 wells while 450 wells are planned for 2006. In addition to exceptional drilling performance in the Gulf of Thailand, value creation is enhanced by performing a high number of IFDP (in-fill drilling projects) whenever possible. This reduces cost by minimizing new platform construction, reusing slots, and reducing installation of new surface casing. The IFDP project can be categorized into two phases:slot recovery; and drilling. This paper focuses on phase 1 of the project, where CTEP uses HWO (hydraulic workover) systems along with cementing, slickline, and wireline services to perform the slot-recovery operations before rig arrival. Topics of discussion include current operational equipment, methods and procedures, logistical challenges, lessons learned, and new development plans intended to further enhance the operation. Statistically, it is estimated that for each single platform 6-well abandonment campaign, CTEP gain 7 to 8 days of drilling time by not utilizing rig time for the Phase I operation. The drilling rig focus is, therefore, maintained on, doing what it does best, drilling new wells safely and economically. Additional wells are drilled with the time saved supplying early gas to meet Thailand's expanding industrial demands. Introduction Before the acquisition of Unocal Corporation by Chevron, Unocal Thailand (UTL) had over three decades of successful energy-development history in the country. With gross natural gas production averaging more than 1.2 Bcf/D from over 100 platforms in the central Gulf of Thailand (GOT), Unocal supplied natural gas to generate over 30 % of the nation's total power demand. Unocal has continued to increase natural gas and condensate production in Thailand since 1981 to meet current and future demands while effectively replenishing reserves. This has been achieved by using advanced drilling and three-dimensional seismic technologies in conjunction with a substantial reinvestment of capital. The small, stacked reservoirs over large areal extent means that well life averages only 2 years and continual drilling and redrilling are required to maximize recovery from shrinking reserves in a mature field. This paper focuses on redrilling or IFDP, where depleted wells are abandoned and slots are reused to drill new wells. This has proved to be a very cost-effective way of gaining more wells without having to build new offshore wellhead platforms and support facilities for these new wells. In the past, the process of making slots of depleted wells available for new wells was done completely by drilling rigs with the exception of cement squeezing off the perforations, where only cement pumping equipment is used. This takes a significant amount of rig time to cut and pull tubings, casings and conductors, set kickoff cement plugs, run splitter conductors, etc. This "non-drilling" period could be better used to drill more wells. This paper discusses details of UTL's process of "well preparation for redrill" and the benefits in terms of rig-day-equivalent (RDE). Background Before 1995, most of the wells in the GOT were completed conventionally with 26-in. driven conductors, 13–3/8-in. to ±1,000 ft, 9–5/8-in. casing to ±4,500 ft total vertical depth (TVD), and 7-in. casing extended to an average depth of 12,000 ft total depth (TD). The 2–7/8-in. tubings are held in place by permanent packers, equipped with sliding side doors (SSD's) for zonal isolation. As the reserves in the ground diminish, the return on investment for new wells also diminishes. New wells have to be drilled in a more cost-saving manner resulting in the emergence of economically attractive slimhole wells. These wells are completed with 9–5/8-in. surface casing to ±1,000 ft, and 7-in. casing to ±4,500 ft TVD. The 2–7/8-in. tubing is then run inside the 6.5-in. open hole (OH) and cemented in place. After these wells are completed, the productions are commingled. Figs. 1 and 2, respectively, show diagrams of typical conventional and slimhole wells.
Abstract As oil and gas developments mature, reservoir depletion reduces field output and fewer opportunities exist to drill new wells. Drilling new wells as the sole means of increasing field production often becomes less profitable, and it presents greater operational risks. Economic risks are also greater as the chance of completing good wells is getting less and the higher capital investment required. In many fields, operators, either intentionally or unintentionally, bypass pay zones during initial development by focusing only on the best zones. Accessing bypassed thinly laminated formations and low-permeability zones is economically attractive but poses several challenges. Several techniques were used to achieve sustainable commercial production from the bypassed zones in East Kalimantan. Hydraulic fracturing and underbalanced perforations were tried, with inconsistent results. Drilling new horizontal wells was not economical. Coiled-tubing (CT) drilling was the solution that provided a cost-effective alternative to the use of a conventional drilling rig. The advantages were a smaller location footprint, shorter trip times, ability to drill underbalanced, competitive rates of penetration, and through-tubing reentry. Because only a few CT drilling campaigns have achieved both operational and production successes, a campaign was proposed that used conventional well design and drilling programs. Previous lessons learned worldwide were used to reduce the drilling risk and enhance the chance of success. This was especially important in drilling a deviated hole through the coal zone of the subject well. This paper will describe three wells from the design phase through post-job evaluation. Lessons learned and improvement plans are also incorporated in this paper. Introduction Cost-effective development of a low-permeability gas reservoir in East Kalimantan's Badak and Semberah fields (Fig. 1, 2) has proven to be difficult. Conventional production techniques have not been able to produce the reserves at commercial rates because of the small and highly compartmentalized reserves. The current production optimization techniques, hydraulic fracturing and extreme underbalanced perforating, showed inconsistent results. A horizontal well was an ideal solution for field development, but because of the size of the reservoirs, drilling new horizontal wells conventionally was not economically attractive. Reentry drilling using existing wellbores was determined to be the best option to develop these fields, and coiled tubing (CT) drilling reentry applications were introduced. CT drilling techniques have evolved in regards to drilling practices and CT workstring limitations. Previous CT drilling experiences in the area were not very successful mechanically, mainly because of the candidate selection process. A joint feasibility study was performed to select well candidates that have a high potential for incremental production with minimum drilling risk. This objective was achieved with the combination of an extensive reservoir engineering study and reviewing lessons learned from other CT drilling operations . A CT drilling reentry campaign was proposed with the key objective of maximizing gas deliverability and reserve recovery in a safer, cost-effective, and timely manner from low-permeability reservoirs and low-productivity wells. Deliverables of this CT drilling campaign were to achieve mechanical success, determine realistic costs, resolve drilling risk and evaluate low permeability reservoir productivity. Feasibility Study A well in the Semberah field that represents the average reservoir characteristics in the area of operation was chosen as the study case. The candidate selection process started by studying potential incremental production from a horizontal well against that of a vertical well, including considering the tubing size and its potential for production restriction. The openhole wellbore size was simulated to evaluate the effect of friction and length on potential production. The length of the openhole segment was reviewed not just from the most likely case to the limitation of CT drilling reach, but also with geological knowledge, limited well control, additional drilling time, cost, and associated drilling risk.
Abstract Since 1990, over 100 hydraulic fracturing treatments have been performed in the Hassi Messaoud (HMD) field in the northeastern part of central Algeria, resulting in an average production increase per well of 700 BOPD. The success of the stimulation program in this 11,150 ft deep, Cambrian-age sandstone formation depended on overcoming the combination of the following treating conditions.–slotted liner and openhole completions in most wells –reservoir thickness of 200 to 500 ft –Young's moduli of 8 to 12E6 psi –fracturing pressures of 0.8 to 1.2 psi/ft –low reservoir pressures of 0.15 to 0.45 psi/ft –formation permeabilities of 0.5 to 50 md –moderately high temperature of 245 F –underlying low-stress saltwater formations Prefrac injection tests and temperature logs were run on almost every well to allow treatment optimization. Proppant amounts range from 10,000 to 300,000 lb of 20/40 and 12/20 sintered bauxite at concentrations up to 15 lb/gal; tip-screenout designs were used on most treatments to maximize fracture conductivity. The collection of comprehensive data in uncommon formation characteristics has led to a much better understanding of the controlling factors in predicting treatment performance. Descriptions of fracturing behavior, well preparation, and production results are presented. Introduction Since the first field operations in the late 1940's, hydraulic fracturing treatments have become key factors in the development of many fields throughout the world. By the late 1980's over 1 million treatments had been performed. Most were performed in the United States, where fracturing has made many low-permeability, hard formations economically feasible to develop. In the last 15 years, there has been significant extension of hydraulic fracturing into softer, moderate- to high-permeability formations. The recent expansion of Frac and Pack techniques in international locations, as well as in the USA Gulf Coast, has further extended fracturing technology to unconsolidated, high-permeability formations. The fracturing treatments performed in the HMD field differ significantly from previous fracturing experience because of a rare combination of hard formation characteristics, low reservoir pressure, and moderate formation permeability. Fracturing pressures in this 11,150-ft deep Cambrian sandstone formation average 0.9 psi/ft, attributable to Young's moduli that vary from 8 to 12E6 psi. With formation permeability averaging up to 50 md and pore pressure gradients that vary between 0.15 to 0.45 psi/ft (resulting from 35 years of field production), fluid loss is often great. Fluid efficiency (percentage of fluid remaining in the fracture at shut-in of a prefrac injection test) averages only 15%, even with the use of large polymer loadings and fluid-loss additives. Complicating matters further are mechanical limitations inherent to treating a mature field, coupled with slotted liner and openhole completions methods. These difficult treating situations make treatment design challenging and stress the importance of well preparation and prefrac data collection. The importance of prefracturing injection testing and understanding the role of fluid loss at large pressure differentials have been significant factors in the success experienced in HMD. Knowledge obtained under these conditions of high pressure differential as well as the experiences gained from fracturing slotted-liner and openhole completions should be of considerable interest as fracturing is extended into nontypical arenas. To best describe the field and fracturing history, subject content will be separated into the following areas: P. 303