Измерение забойных параметров в режиме реального времени для повышения эффективности кислотных обработок на месторождении каспийского региона Мансур Аглямов, Данияр Агрынов, Артем Савин, Николай Кулинич, Антон Буров, Общество инженеровнефтяников, Константин Бурдин, Общество инженеров-нефтяников, Шлюмберже Авторское право 2014 г., Общество инженеров нефтегазовой промышленности Этот доклад был подготовлен для презентации на Ежегодной Каспийской технической конференции и выставке SPE, 12 -14 ноября, 2014, Астана, Казахстан.Данный доклад был выбран для проведения презентации Программным комитетом SPE по результатам экспертизы информации, содержащейся в представленном авторами реферате. Экспертиза содержания доклада Обществом инженеров нефтегазовой промышленности не выполнялась, и внесение исправлений и изменений является обязанностью авторов. Материал в том виде, в котором он представлен, не обязательно отражает точку зрения SPE, его должностных лиц или участников. Электронное копирование, распространение или хранение любой части данного доклада без предварительного письменного согласия SPE запрещается. Разрешение на воспроизведение в печатном виде распространяется только на реферат объемом не более 300 слов; при этом копировать иллюстрации не разрешается. Реферат должен содержать явно выраженную ссылку на авторское право SPE.
Efficient reservoir sweep is critical for operators to boost oil production in the Middle East. This task becomes particularly challenging in carbonate formations, which typically feature permeability ranging from microscopic pores to large cavernous vugs. Extreme heterogeneity disserves water injectors, leading to nonuniform injection profiles. Consequently, water sweeping is inefficient and leaves significant residual oil behind. In the Mesopotamian Basin, the matrix stimulation approach was rethought to address high permeability contrasts and produce the bypassed oil. The methodology relied on coiled tubing (CT) equipped with fiber optics and real-time downhole measurements, a CT-deployed inflatable packer, and a high-pressure rotary jetting tool. The array of downhole readings was leveraged to ensure optimal use of the bottomhole assembly. The high-pressure rotary jetting tool was used in the first run to condition the wellbore tubulars across the inflatable packer planned anchoring depth. In the second run, the inflatable packer was set at the target depth, and the stimulation treatment was selectively pumped either above or below the packer, depending on the depth of the interval of interest. The proposed stimulation technique was implemented in more than 40 wells, which included vertical and deviated water injectors, completed with 3 1/2-in. or 4 1/2-in. tubing and up to 7-in. casing, with two to five perforated intervals averaging 30 to 50 m in total, temperatures ranging from 90 to 140°F, and an average meadured depth of 2500 m. The CT-deployed inflatable packer had an expansion ratio of up to 3 to 1. CT real-time downhole measurements, such as CT internal pressure, CT annulus pressure, temperature, downhole axial forces, gamma ray, and casing collar locator (CCL), were instrumental to eliminate the uncertainties associated with changing downhole conditions and depth correlation. They also enabled a controlled actuation of the downhole tools in subhydrostatic wells, as the pressure imbalance caused by the low bottomhole pressure can generate loss of fluid flow and pressure across the tools. For the first time, the operator was able to stimulate the tight rock in water injector wells, enhancing injection sweeping efficiency and boosting oil production from offset wells. As a result of this campaign, production gains are estimated at 60,000 BOPD, and injectivity increased in average 2 times per intervention. This approach has now become the state of the practice for the operator to stimulate wells with high permeability contrast. This enhanced matrix stimulation technique, leveraged by CT and real-time downhole measurements, brings a new level of confidence to accurately and effectively deploy inflatable packers in wells with challenging expansion ratio and low reservoir pressure. In addition, the proposed technique enables stimulating tight rock across intervals with extreme heterogeneity, resulting in a more efficient sweep and an increase in oil production.
Achieving efficient reservoir sweep is a challenging task in formations with extreme heterogeneity. For instance, the presence of natural fractures in carbonate injector wells often prevents obtaining uniform injection profiles. This represents a major challenge for field development, not only due to poor reservoir sweep efficiency, but also due to early water breakthrough in producer wells. To treat both problems, a new approach to executing conformance treatments in water injectors was implemented in the Middle East. The proposed methodology yields a uniform injection profile by combining two contrasting treatments in the same operation: mechanical isolation and chemical suppression of the high-intake zone and stimulation of the low-intake zone. Isolating target zones with a coiled tubing (CT) deployed inflatable packer enabled combining the suppression and stimulation treatments in a single intervention. Each treatment can then be tailored by leveraging real-time CT downhole measurements, and injection profiles can be balanced by adjusting the degree of suppression and stimulation based on the target injectivity index for each zone. This new approach was successfully implemented in more than 10 injector wells. The CT-deployed inflatable packer allowed dividing the operations in two separate treatments, above and below the packer, on the same run. The stimulation treatment was performed on tight zones, immediately followed by a suppression treatment on the dominant section. That suppression helped reduce injectivity across the main interval by pumping suppressant material—calcium carbonate—in varying concentration and batch size. Treatment progress was evaluated and controlled in real time thanks to CT downhole sensors, which monitored the response of the formation as each batch hit target intervals, until the desired injectivity index reduction was achieved. The ability to make fast, informed decisions based on those downhole measurements was the cornerstone of this new conformance methodology, which allowed full control of treatment execution by monitoring changes in injectivity on the spot. After each treatment, an injection logging tool (ILT) was run to assess the final injectivity profile. ILTs showed an average improvement above 60% on well conformance even several months after the treatment, indicating a balanced injection distribution between the zones. In certain cases, injected water distribution was found completely equalized between weak and dominant zones. This allowed maintaining equal pressure support across all zones and balancing the production profile in the adjacent producer wells. Improving the injection profile by performing selective stimulation treatments had been already proven successful in the subject field. The new approach further developed selective stimulation to achieve an unprecedented level of conformance in this highly heterogeneous formation while bringing an estimated gain of 75,000 BOPD from the first 10 intervened wells, which represents a 50% improvement with respect to the previous methodology.
Carbonate acidizing is one of the main techniques for improving the production and injectivity in oil and gas fields. Various studies and field stimulation results were analyzed to develop a fit-for-purpose acid stimulation treatment design placed with coiled tubing in which diversion is achieved by using in-situ gelation, emulsified diverting acid, degradable fibers, or combinations of these methods.The lack of downhole fluid placement control during the pumping of stimulation treatments may cause these jobs to not achieve the maximum stimulation effect or even fail, which may eventually call for more costly solutions.An innovative stimulation approach was applied on a sour gas injector well in a carbonate oil field in the Caspian region. The field is characterized as a naturally fractured, thick, and prolific carbonate formation with high H 2 S content. To dispose of H 2 S and improve oil recovery, the produced sour gas is injected back into the reservoir through injector wells. An innovative method using fiber optic technology for acquiring distributed temperature survey (DTS) measurements and a real-time downhole sensor tool providing pressure and temperature measurements and casing collar location were used in this well to improve its injection potential.DTS technology was utilized to better understand the movement of stimulation fluids into the reservoir through real-time monitoring, thus providing the capability to optimize the acid injection along the target zone. The DTS analysis during the post-acid injection stage identified crossflow and provided good correlation between acid reaction with carbonates and proportional warm-back trends along the formation.The adoption of the technique enabled increased overall confidence in decision making during treatment execution, which allowed an improved placement strategy, resulting in increased stimulation effectiveness. This technology has the potential to become the next important step in the evolution of acid stimulation strategies in the Caspian region.
Tengiz is a unique, super-giant oil field located in western Kazakhstan that is characterized as a fractured carbonate reservoir with high concentrations of H2S. It is operated by TengizChevroil (TCO). Current production is ~ 530,000 BOPD from 70 active producing wells. As part of an effort to increase the field's production output, a workover and stimulation program was initiated in 2011 after a hiatus of more than five years from such activities. A sizeable part of this workover effort was a matrix acid stimulation program which took lessons learned from earlier acid stimulation campaigns in the Tengiz Field to develop a modified acid stimulation treatment design. The result of this most recent program was a significant and sustained response in well productivity. The key components of the 2011/2012 acidizing program include: 1) increased acid volumes ranging from 50-100 gal/ft and 2) an acid diversion system that included the use of a viscoelastic diversion acid and degradable fibers. Another factor that supported the success of the acid stimulation program was the involvement of a multi-disciplinary team that addressed both candidate selection and acid stimulation design. The TCO 2011/2012 Acid Program has shown incremental improvement in all 19 wells stimulated to date. The average initial incremental gain following stimulation is ~4, 240 BOPD per well and the overall improvement in the Productivity Index (PI) has more than tripled. Post-stimulation production logs have confirmed improvement in the production profiles, indicating the acid diversion methods are having a positive impact.
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