Se, Yegor (Chevron Energy Technology Company) | Villegas, Mauricio (Chevron) | Iskakov, Elrad (Chevron) | Playton, Ted (Tengizchevroil) | Lindsell, Karl (Tengizchevroil) | Cordova, Ernesto (Chevron Energy Technology Company) | Turmanbekova, Aizhan | Wang, Haijing
Secondary oil recovery projects in naturally fractured carbonate reservoirs (NFR) often introduce uncertainties and challenges that are not common to conventional waterfloods. The recovery mechanism in NFRs relies on ability of the fracture network to deliver enough injected fluid to the matrix, as well as rate and magnitude of capillary interactions within the matrix rock, during which hydrocarbon displacement occurs. The imbibition measurements can be performed in the laboratory using core samples, but due to reservoir heterogeneity, certain limitations of the lab equipment and the quality of the core material, scalability of the core results to a reservoir model can be challenging.
This paper describes the design, execution and evaluation of the’ log-soak-log’ (LSL) pilot test conducted in a giant naturally fractured carbonate reservoir with a low-permeability matrix in Western Kazakhstan, where repeatable and reliable measurements of changes in water saturation were achieved across large intervals (tens of meters) using a time-lapse pulsed-neutron logging technique. Periodic measurements provided valuable observations of dynamic change in saturation and fluid level over time and allowed estimation of the rate and magnitude of imbibition in the slope margins, depositional settings and rock types of interest. Incorporation of the LSL results into reservoir models validated the ranges of water-oil relative permeability curves, residual oil saturation to water, irreducible water saturation, and capillary pressure assumptions. This validation constrained key subsurface uncertainty and updated the oil recovery forecast in several improved oil recovery (IOR) waterflood projects.
A practical method for estimating the directional permeabilities in anisotropic reservoirs is presented. The method uses pressure-transient-analysis results from at least three sets of interference/pulse tests among wells offset at different azimuths. Knowledge of the maximum/minimum permeability directions in anisotropic reservoirs helps to optimize injectors/producer locations, and is important for reservoir management especially under secondary/enhanced recovery of hydrocarbons. The proposed method uses transient-test data rich with dynamic information aiming to provide field-wide permeability distribution in well-spacing scale, which is relevant for estimating fluids movement and recovery. Its application in a carbonate oil-field in Kazakhstan is also discussed.
The proposed method uses well coordinates and multiple sets of analysis results of interwell transient tests through mathematical matrix operations. It is straight-forward to use and works efficiently. The algorithms to calculate directional permeabilities in anisotropic homogeneous reservoirs from interference-tests were first introduced by
The proposed method was validated using synthetic cases. Its application in a large set of multiple-well tests in a naturally fractured reservoir illustrated its practicality and efficiency. Extensive interwell transient data have been collected and analyzed from carefully designed and conducted tests among 12 wells in Korolev (a carbonate field in Kazakhstan). Ten of twelve wells each have interwell tests at three different directions, and that allows the calculation of directional permeabilities. The permeability-tensor map is generated for the entire field and compared with the fracture orientations derived from geological structure and image-log interpretation. Both static and dynamic data resources indicate fracture orientations vary substantially throughout the field. In some areas, the dominant permeability directions from interwell transient data are consistent with those from image-log. However, they differ in other areas emphasizing the need for using dynamic measurements in well-spacing scale for better understanding of fracture distributions/orientations and their impacts on flow communications among wells.
The novelty of this method of estimating directional permeabilities is that it uses well coordinates and analysis results of individual interwell transient tests directly in heterogeneous reservoirs. It is convenient and efficient. It can be easily used to generate a field-wide permeability-tensor map using dynamic transient data. Its application in a large carbonate reservoir demonstrates its practicality even in fields with complex varying anisotropy. Integrating the results from this method with those from geological and petrophysics analyses reduces uncertainty in reservoir characterization.
The development of the giant Tengiz and Korolev oil fields might require a large and reliable industrial water source for future development. This paper shares best practices from a multidisciplinary team effort in characterizing the shallow aquifer water sources in the Tengiz area. The data set above the Tengiz oil zone is characterized by limited cores and large number of penetrations with logs, as well as 3D seismic.
A subsurface study of the Tengiz area Post-Salt aquifers is challenging because of the old vintage of existing logs and limited core in shallower section of wells targeting Tengiz and Korolev oil reservoirs. A subsurface data gathering program was executed to acquire new logs, core from two new wells A-1 and B-1 from Alb-Cenomanian, Upper Neocomian, Aptian and Jurassic formations. All core and log data in conjunction with seismic improved our understanding of the depositional environments, connectivity and areal extend of numerous sand bodies. Core porosity and permeability very well match with new wireline logs. Based on information gained and new interpretation data, we now have better understanding of the geology of potential water source sands.
Alb-Cenomanian and Upper Neocomian deposits were found to be the two largest aquifers in the Tengiz area. The Alb-Cenomanian has high net-to-gross with extensive fluvial channel belt sandstones. Reservoir properties are very good and water volume is very large. The Upper Neocomian consists of ribbon-like fluvial channel belts (2-15m thick) embedded within floodplain deposits and interbedded thin (i.e., <2m) crevasse splay deposits. Reservoir sandstone is moderate to excellent quality. The Upper Neocomian has stratigraphic barriers above and below – internally it exhibits some baffles and barriers associated with floodplain shales. Aptian and Jurassic sections were evaluated to be unattractive as water sources. Because of sand quality and higher water volume, Alb-Cenomanian and Upper Neocomian formations were selected as the best candidates for water source.
New seismic interpretation, log and core data were incorporated to construct static models. Dynamic models for shallow aquifers are being built; the models will be used to support the industrial water source development plan for Tengiz and Korolev oil fields.
Abdrakhmanova, Aizada (Tengizchevroil) | Iskakov, Elrad (Tengizchevroil) | King, Gregory R (Tengizchevroil) | Chaudhri, Moon Mansoor (Tengizchevroil) | Liu, Ning (Tengizchevroil) | Bateman, Philip (Tengizchevroil)
Tengizchevroil (TCO) operates two giant carbonate oil fields, Tengiz and Korolev, located on the northeast shore of the Caspian Sea in Kazakhstan. Both fields are Middle Devonian to Upper Carboniferous isolated carbonate platforms. Since 1991, the fields have produced around 2B barrels of oil. As more geologic and dynamic data becomes available, an updated history match of the existing dynamic field models is required to provide more accurate simulation results for estimating reserves, optimizing production and assessing future field development opportunities.
In this paper, we present a case study on the use of brown-field design of experiments (DoE) on dual-porosity and dual-permeability Korolev field simulation model. Korolev is a highly fractured reservoir, and the physics of fluid movement is mainly controlled by the fracture network. In order to capture the uncertainty in the extent of fracture region at Korolev, discrete low, mid and high fracture models were created. The history matching process was split into three separate DoE studies, one for each of the fracture models, to obtain good quality proxies. After history matching the three fracture models separately, a combined proxy was created, and the final probabilistic P10, P50, P90 models were selected from the suite of all low, mid and high fracture extent models.
The history matching workflow consisted of selecting uncertainty parameters and ranges which honor geological data, identifying parameters having high impact on the history match quality, conducting brown-field DoE of historical and prediction periods, developing proxies for EUR objective functions and history match mis-match functions, and model selection. The majority of history matching effort was spent on the static well pressure match, followed by minimizing the modular dynamic test (MDT) pressures, production logging tool (PLT) profiles and water cut mis-match functions. Approaches in key areas which helped to improve the quality of Korolev history matched models will be discussed in detail.
The history matching workflow with low, mid and high fracture models described in this paper is believed to be superior to approaches that use a single fracture realization with fracture porosity, fracture permeability and sigma (fracture-matrix interaction term) history match modifications within the simulator. This is because the use of three fracture realizations allows for adjustment of intrinsic fracture properties (fracture density, aperture size, fracture extent, etc.). In addition, the use of three separate DoE studies allows for more accurate proxy model development.
TCO is a joint venture formed in 1993 between Chevron, ExxonMobil, KazMunaiGas, and LukOil. It operates two carbonate oil fields, Tengiz and Korolev, located in Pre-Caspian basin in Western Kazakhstan (Figure 1). Korolev is a satellite of the giant Tengiz fieldand is characterized by thick oil column and well developed system of natural fractures.
The Korolev Field is an isolated carbonate build-up, consisting of a single, naturally fractured reservoir which is subdivided into six sequences (from oldest to youngest: Devonian, Tournaisian, Early Visean, Late Visean, Serpukhovian, and Bashkirian (Figure 2)).
Byers, Lawrence (Chevron) | Wessel, Helen Mary (Chevron) | Kalelova, Anargul (Tengizchevroil LLP) | Korsyuk, Alexey (Tengizchevroil LLP) | Tulegenova, Gulmira (Tengizchevroil LLP) | Subkhankulova, Aliya (Tengizchevroil LLP) | Zhilkaidarova, Ainur (Tengizchevroil LLP)
Gas flaring reduction is a hot topic in the Oil & Gas industry. In the paper, we will delineate how TCO achieved its goal by executing projects through commitment, hard work, embracing technology and with cooperation with the partners and local government. Of particular note, we will discuss how TCO demonstrated that flare reduction, gas utilization and increased production can be achieved simultaneously.
As of the end of 2009, TCO eliminated the practice of continuous flaring from its gas processing. Today, the only flaring which occurs in TCO’s operations is purge and pilot flaring and some non-continuous flaring for maintenance, repairs and process safety. Over a decade, TCO executed multiple major capital projects to reduce flaring, culminating with the successful execution of its four-year, Gas Utilization Project. TCO’s efforts in reducing gas flaring, and in particular its Gas Utilization Project, resulted in recognition of TCO in 2012 the World Bank’s Global Gas Flaring Reduction (GGFR) Forum in London in which TCO received “Excellence in Flaring Reduction Award”.
TCO continues to make steady strides toward total flaring elimination; for instance, TCO recently completed its new Japanese automation software project. During the first acid gas flaring event in summer 2012, TCO successfully applied the Japanese automation software. It is worth noting that TCO is the first operator in ROK to use this Japanese - developed control software. The journey continues in TCO to see if further improvements can be cost-effectively achieved.
This paper presents information regarding past traditional flow-assurance analyses at an example field, along with an example using a new multidisciplinary method that integrates geological information into the analyses, resulting in a detailed asphaltene matrix risk profile for this reservoir.
During the past asphaltene flow-assurance risk assessment, the traditional analyses have revealed some anomalous results such as asphaltene onset pressure (AOP) being detected from some fluid samples while not being detected from others. The apparently inconsistent AOP results are critical to understanding how to guide flow-assurance measures. Therefore, all available asphaltene data were re-assessed in all aspects to attempt to clarify asphaltene risk.
Asphaltene issues have often been discussed by multidisciplinary teams consisting of petrophysicists and engineers with well, production, reservoir, chemical, or pipeline backgrounds because such multidisciplinary approaches can deliver fresh eyes to redefine problems. This paper, as a new approach, demonstrates the worth of uniting a further discipline, geoscience, with flow assurance. A synergy between reservoir engineering and geoscience (geology and geohistory) has been developed to explain AOP results for this complex fluid. The results should help flow-assurance specialists to better define the asphaltene operating envelope, which will be used for reservoir and production operations optimization. In addition, these results should be useful for optimizing data surveillance, flow assurance, and for defining new sample acquisition plans. These findings may also be helpful in minimizing future sampling and fluids analysis while achieving reliable flow assurance.
Tursinbayeva, Damira (Tengizchevroil) | Lindsell, Karl Michael (Tengizchevroil) | Zalan, Thomas Anthony (Tengizchevroil) | Dunger, Darrin Allen (Chevron Corporation) | Kassenov, Baurzhan (University of Tulsa) | Howery, Randy (Tengizchevroil)
Over the field life, surveillance in Tengiz oil field has provided historical and baseline data for simulation history matching, static and dynamic reservoir characterization and modeling, and the foundation for efficient well management. Hence, it continues to be an important part of everyday field operations. At the surveillance planning stage, the comprehensive opportunity list of well candidates is developed based on input provided by members of multiple teams: geologists and petrophysists, production and reservoir engineers, drilling and field operations specialists. SCADA system, permanent downhole gauges (PDHGs) and multiphase flow meters (MPFMs) are widely implemented for production data acquisition and analysis. However, the majority of surveillance activities still need well intervention into the high pressure, high H2S concentration wellbores, often during harsh weather conditions. Each job execution plan is therefore focused on the safest procedure to obtain the necessary data. Each planned survey in the surveillance plan is ranked according to the value of information to be obtained, in order to help schedule the timing of surveillance based on plant production needs.
The ultimate goal is to safely execute planned surveillance to support production optimization and field development work. This paper will highlight TCO success in addressing the different reservoir and well production uncertainties through a properly designed surveillance plan with both short and long-term objectives.
Macary, Sameh Monib (TengizChevrOil) | Tenizbaeva, Biganum Marabaevna (TengizChevrOil) | Azhigaliyeva, Aizada (TengizChevrOil) | Yessaliyeva, Arailym (TengizChevrOil) | Seitim, Malika (TengizChevrOil) | Iskakov, Elrad (TengizChevrOil)
Tengizchevroil (TCO) has had up to 20 years of experience in industrial Waste Water Disposal (WWD) into the subsurface. TCO industrial waters cannot be recycled or utilized for any other purposes, hence, malfunction of any component of WWD system (especially wells) can lead to production curtailment. Therefore, TCO has identified the WWD wells as "critical?? wells in the business unit.
Waste water is injected into three disposal wells; there are six monitoring wells that provide important information about reservoir pressure, the change in chemical composition of water samples, the fluid level and wellhead performance. Regular surveillance is a key to get data, such as reservoir pressure, temperature, downhole samples, reservoir connectivity, etc. This is important to build the correct reservoir model, both static and dynamic with immediate interest in identifying the water front movement and eventual water breakthrough wells.
In the light of expected operational activities, optimization projects and commercial oil growth, WWD activities are planned to be expanded. Drilling new wells is proposed to add spare injection and monitoring capacity to the project. Additional services, surveillance steps, well geometry and completion design optimization is considered for all new wells.
Cross-functional efforts of subsurface earth scientists and petroleum engineers, lab technicians/facility engineers/environmental specialists/regulatory teams are critical to achieve technical excellence, and hence to fulfil regulatory requirements. Third party involvement in lab analyses and results interpretation strengthens confidence in the operator's efforts to maintain and protect the environment according to official agencies vision.
Kashagan is a super giant offshore carbonate field which was discovered in 2000 by a consortium of oil companies (currently, affiliates of): ExxonMobil, ENI, Shell, TOTAL, Conoco-Phillips, INPEX and KazMunaiGaz. The field is located in an environmentally sensitive area of the North Caspian Sea. The field is a deep, large structural relief, over pressured, isolated, carbonate build-up with a high-permeability, karstified and fractured rim and relatively low-permeability platform interior. The field contains a sour, undersaturated light oil with a large gas content. High pressure miscible gas injection is planned for oil recovery enhancement, as well as sulfur management.
No-one doubts the importance of flow assurance in offshore projects in particular. Moreover, it is now well known that gas injection operations require the evaluation of asphaltene deposition risk. The consortium has undertaken extensive evaluations to ascertain the likelihood of any flow assurance risks from subsurface to surface. During the asphaltene risk evaluation, many bottomhole samples have been collected and analyzed for asphaltene content, asphaltene onset pressure (AOP), and SARA (saturates, aromatics, resins and asphaltenes). These continuous analysis efforts have revealed some anomalous results such as AOP being detected from some fluid samples while not being detected from others.
The apparently inconsistent AOP results are critical to understand how to guide flow assurance measures. Therefore, all available asphaltene data were re-assessed in all their aspects to attempt to clarify asphaltene risk. This paper presents a multidisciplinary approach where a synergy between reservoir engineering and geoscience (geology and geohistory) has been developed to explain AOP results for this complex fluid. The results should help flow assurance specialists to better define the asphaltene operating envelope, which will be used for reservoir and production operations optimization. In addition, these results should be useful for optimizing data-surveillance, flow assurance, and for defining new sample acquisition plans. These findings may also be helpful to minimize future sampling and fluids analysis while achieving reliable flow assurance. The paper will show examples of the related flow assurance analyses, and the geological information which were incorporated in the study, resulting in a detailed asphaltene matrix risk profile for this reservoir.