Acidizing treatments in carbonates often result in significant skin decrease due to high reactivity of the formation with acids. Noticeable production increase or inability to run analysis tools after the treatment may lead to the conclusion that the matrix acidizing job was performed efficiently, when, in fact, the job was not optimized in terms of fluid volumes, acid types, wellbore coverage, and pumping rates. As a result, the final skin is not as low as it could be, and, most importantly, medium - and long-term post-acidizing production decline is faster than it could be with an optimized treatment. To overcome these concerns, an integrated approach to acidizing treatments was implemented for different oil fields in Kazakhstan. The integrated approach consists of comprehensive laboratory testing, which includes core flow tests with subsequent 3D computer tomography scanning. The tests help to determine wormholing regimes and channel geometry while providing calibration points for acid-rock interaction curves. These coefficients are used in the acidizing modeling software, which enables optimization of fluid volumes, pumping rates, and diversion strategy. The approach suggests the use of a single-phase retarded acid system is the most effective method of keeping the treatment in the dominant wormhole regime, especially at elevated temperature. The integrated approach loop is closed by the analysis of the distributed temperature sensor data to calibrate the efficiency of diversion and reservoir injectivity profile. The approach was introduced for different oil fields in Kazakhstan, with a variety of conditions: depths up to 5000 m and temperatures up to 145°C. The approach helped to optimize acid volumes by as much as 44% to achieve an optimum skin. In the mid-term perspective, this approach helped to reduce the production decline rate by at least 20%, and ongoing post-treatment analysis is even more promising.
One of the strategic targets in Yamal autonomous district, the Turonian siltstone formation, lies above the Cenomanian formation and is separated by a massive argillite barrier. Successful stimulation experience in vertical wells in the North-Kharampurskoe field during 2008 to 2010 encouraged the operator planning the next step of field exploration to consider horizontal well completions using multistage stimulation. The paper will describe pilot campaign in details. The Yamal Turonian formation was formed in a coastal marine environment with slow deposition rates and is composed primarily of siltstone. The major challenges of the Turonian formation are low permeability (∼0.5 md) and extremely high clay content—chlorite, kaolinite, illite, and mixed-layer illite-montmorillonite. The low temperature of the Turonian formation (below 80°F) also presents a significant challenge for gas production. An operator must produce at minimum drawdown to avoid hydrates creation. The shallow reservoir depth (∼ 3,000 ft) restricts recovering potential energy stored inside of the formation (initial reservoir pressure of about 1600 psi); therefore, hydraulic fracturing is a must for economic development of the Turonian formation. Selecting the correct fracturing fluid required extensive laboratory tests for compatibility and rheology adjustments. Thorough optimization of the fracturing fluid with clay stabilizer was applied during the course of this project. Additional challenges included proppant flowback tendency and inefficiency of conventional methods (resin-coated proppant) at such low temperatures. The project began by stimulating a vertical well that was used as a reference for the fracture horizontal well that was stimulated in three stages. Coring and a full logging suite were performed on the reference well, including acoustic measurements, post-frac, to obtain fracture height growth. It was shown that fracture is vertical at such depth and that it covers the whole interval without vertical growth into argillaceous barriers. Bottom hole gauges were used to complete the precise mechanical modeling of the stimulated reference well. Evaluation of the mechanical and properties were completed using E&P software platform-based simulator to optimize the multistage fracturing design in the horizontal well. This paper includes a detailed sequence of the operations performed and explains conclusions made concerning fracture geometry. The lessons learned during the assessment campaign are described. This stimulation project performed in the North-Kharampurskoe field is fundamental in development of the field and serves as important step toward unlocking the gas potential of other Turonian siltstones.
Авторское право 2015 г., Общество инженеров нефтегазовой промышленности Этот доклад был подготовлен для презентации на Российской нефтегазовой технической конференции SPE, 26 -28 октября, 2015, Москва, Россия.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. РезюмеТуронский газоносный пласт, один из основных стратегических ресурсов в Ямало-Ненецком округе, залегает над Сеноманским песчаником и отделен мощной толщей аргиллитов. Успешная кампания по гидроразрыву пласта в вертикальных скважинах Северо-Харампурского месторождения в 2008 и 2010 годах стала предпосылкой для следующего шага недропользователей в изучении перспектив разработки залежи. Статья содержит детальное описание проекта МГРП.Туронская залежь Северо-Харампурского месторождения представляет собой алевритистый песчаник. Основными трудностями эксплуатации объекта являются низкая проницаемость (~0.5 мД) и высокое содержание глинистых фракций -хлорита, каолинита, иллита и монтмориллонита. Низкая пластовая температура (менее 27°С) представляет вызов для разработки из-за риска формирования газовых гидратов. Небольшая глубина залегания (менее 1 км) в свою очередь ограничивает потенциальное энергию на подъем углеводородов (пластовое давление порядка 110 атм). Таким образом, гидроразрыв пласта является единственным способом рентабельной эксплуатации объекта. Была проведена оптимизация жидкости ГРП по стабилизации пластовых глин. Дополнительные сложности, заключались в тенденции к выносу пропанта из трещины и температурным ограничениям традиционных пропантов со смоляным покрытием (RCP).Кампания началась с гидроразрыва вертикальной скважины, спроектированной в качестве опорной исследовательской скважины для последующего трех-стадийного ГРП в горизонтальной скважине. Исследовательская скважина обеспечила максимальную полноту информации -в ней были проведены отбор керна и расширенный комплекс каротажных исследований, включающих запись широкополосной акустики позволивший определить границы вертикального роста трещины. Так, было показано, что трещина ГРП распространяется вертикально и вскрывает всю толщу туронской залежи. При этом отсутствует вертикальный рост в покрышки аргиллитов сверху и снизу газоносного пласта. Датчики забойного давления были использованы при ГРП для более точного моделирования геометрии т...
The fracturing fluid is the essential part of any hydraulic fracturing treatment. A borate-crosslinked guar-based fluid is one of the most commonly used types of fluid. The first mention of guar derivatives crosslinked with boron can be traced back to 1977. Scientific papers that describe boron equilibria as a function of the fluid pH can be trackedback to 1966. Comprehensive studies of the rheological behavior of borate-based fluids were performed in 1980s and 1990s, and for almost 30 years, it has been considered as a well-known topic. Recently, a few authors reported a significant decrease in viscosity of the fluid at elevated pressure. This decrease was reversible (i.e., as soon as the pressure values are moved back to the normal, the viscosity is recovers). Such effect can significantly affect the stimulation design and outcome because most of the time the slurry is affected by elevated temperatures and pressures. Still, many questions remained unanswered. One of them is the effect of crosslinker concentration/composition on the stability of the fluid at highpressure. Another is the comparison of the fluid viscosity under the ISO 13503-1 ramp at standard conditions and elevated pressure. The last one concerns the actual values of the fluid rheological parameters, n and K’, under different pressures. In this paper, we investigate the fracturing fluid behavior under high pressure. For the first time in the industry, we compare the results of ISO fluid stability testing, and the fluid shear recovery under 400-psi pressure and up to 10,500 psi. Finally, using a novel hydraulic fracturing simulator, the effect of the pressure-sensitivity of the fluid on the proppant transport, fracture geometry, and, subsequently, well productivity will be demonstrated. The findings of this paper will have noticeable impact on the design of the hydraulic fracturing treatment where borate-crosslinked fluids are used.
Rheology of fracturing fluids described by power law model. The coeffects n and K of this model is using for all fracturing stimulators. Rheology measurements of real fracturing fluid frequently provide values with n >1, which is contradicted with Power Law model.Transfer this number to a fracturing simulator software gives wrong fracture simulation. The paper describes a new approach for modeling of fluid viscosity which resolves wrong assumptions of previously used model. Fluid viscosity measured with high-pressure-high-temperature (HPHT) rotational rheometer. The conventional fluid testing procedure based on ISO 13503-1 standard requirements provided erroneous and inexplicable results. The investigation of fluid rheological behavior was done by measurement of fluid viscosity in extended range of shear rates. Contrary to usual measurements of viscosity at 25, 50, 75 and 100 s-1, during this approach shear rates range was extended to 340 s-1 and 5 s-1. Fluid behavior was analyzed using log-log regression approach. Base on this analysis the corrected rheology numbers calculated and used tor a stimulation software. As a result of laboratory research, Power Law model inapplicability in several cases was confirmed. Number of rheological measurements revealed boundary conditions for implementation of Power Law model and enlighten the factors which causes non-linear relation of viscosity at log-log plot. It has been found that pH, temperature and polymer degrading material cause abnormal fluid behavior at 1-100 s-1 shear rates range. Therefore, limitations for measurements according to ISO 13503-1 standard was stated. Additionally, impact of recently introduced oil and gas producing companies’ fracturing fluid quality standards on fluid viscosity behavior was evaluated. It was revealed that tough requirements for fracturing fluid viscosity recovery after passing through high shear rate region provoke abnormal viscosity loss at low shear rates and errors in determination of consistency and behavior indexes. Finally impact of wrong data obtained with Power Law approximation on fracture geometry calculated with currently available fracturing simulators was estimated and requirements for next-generation fracturing simulators in terms of fluid viscosity modeling was claimed. The study shows weak points in implementation of currently used Power Law fluid viscosity model for fracturing simulation. Implementation of practices described in this study allow to either don't cross the border of power law model or to enrich fracturing simulators with more precise rheology model.
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