Arisandy, Mellinda (PETRONAS Carigali Indonesia Operations) | Mazied, Miftah (PETRONAS Carigali Indonesia Operations) | Putra, Bayu P (PETRONAS Carigali Indonesia Operations) | Yogapurana, Erik (PETRONAS Carigali Indonesia Operations) | B Mohd Idris, Jamin Jamil (PETRONAS Carigali Indonesia Operations) | Darmawan, Hendra I. (PETRONAS Carigali Kuala Lumpur)
This paper describes geochemistry analysis, hydrocarbon charge and entrapment model for prolific "MA" Block in the West Natuna Basin. Even though the area is currently at a mature exploration stage, the behaviour of hydrocarbon distribution in the area is still poorly understood and the link between discovered hydrocarbon and possible kitchens is still unknown. This study is an attempt to understand hydrocarbon expulsion, charging and entrapment in "MA" Block to de-risk further exploration efforts.
Several localized inverted half-grabens were identified through seismic interpretation. Nearby wells were then selected in evaluating source rock quality and maturity. In order to determine hydrocarbon expulsion model, 1D-3D burial history and thermal maturity models were constructed using integration of source rock and fluids geochemistry, temperature, seismic, and well data. Hydrocarbon charge and entrapment models were then simulated using 3D basin modeling software and calibrated with existing proven accumulation to produce a risked understanding of hydrocarbon distribution in the study area.
This study suggests that the most possible source rocks are the Late Eocene and Oligocene shales of Lama Formation and Lower Gabus Formations. Both source rocks are indicated by type I & type III kerogen. Lama source rock was confined in the initial grabens and post mature in deep paleo-grabens. This study confirmed that charging is derived from four (4) kitchen areas: Anoa, Gajah, Kakap, and Kambing grabens. The oil samples from "MA" Block indicated lacustrine facies. Rock geochemistry analysis portrayed oil-prone and gas-prone source rock.
In general, hydrocarbon was migrated from the southeastern area (Kambing graben) and southwestern area (Gajah graben). Hydrocarbon was later on accumulated in the nearest structural entrapments (anticlines). In the deep grabens (Kakap and Kambing), the hydrocarbon expulsion was starting as early as 37 Ma and 31 Ma, respectively, while in shallow graben (Anoa) the expulsion was starting at 29 Ma. The earliest structural trap commenced at 21 Ma, aligned with the initial compressional regime that was affecting the West Natuna Basin. Notable accumulative erosion in Miocene was nearly 1000 m at inverted structures, by which partly removed regional seal and reduced reservoir effectiveness. Significant yet-to-find hydrocarbon is predicted to be concentrated in the Anoa, Kakap, and Northeast Kambing area.
Previously, Al-Saedi and Flori et al. 2018d proposed a novel steam-low salinity EOR technique called low salinity-alternating-steam flooding (LSASF) into a reservoir core with a high reservoir temperature. Naturally, if a reservoir's temperature is very low, then oil is heavy. Using thermal EOR techniques in such a low-temperature reservoir resulted in considerable heat loss. In this study, we investigate the steam lifespan from the injector to the producer in order to check if the injected steam is still active throughout the flooding process or if it will condense because of the heat loss. The Bartlesville Sandstone Reservoir, as with other heavy oil reservoirs, is a low temperature (23°C) shallow reservoir containing heavy oil (600 cP). We believe that steam injected into various cores from the Bartlesville Sandstone Reservoir will condense due to the low reservoir temperature. The question is whether or not this condensed steam behave similarly to low salinity (LS) waterflooding.
First, the steam was injected into the oil-free core to determice when the steam condensed and what temperature it condensed at by using a multi-port model to check if the injected steam turned into water.
Several Bartlesville Sandstone Reservoir cores were initially flooded with formation water (FW), and then were flooded with different scenarios of steam and LS water. The temperatures of the inlet, the core, and the outlet were recorded. The effluent was collected from different ports out of the cores and different producer positions in order to follow up the steam position inside the core.
Core contact angle measurements were conducted throughout the flooded cores to determine the wettability alteration between steam and condensed steam (LS water) with the rock.
This study shows that when steam turned into LS water, the sandstone core wettability was altered towards being more water-wet. The condensed steam is considered to be hot LS water, which can reduce oil viscosity and alter the wettability at the same time.
These results were for short length cores. If these results are upscaled up to the oil reservoir scale, then the steam will still be turned into LS cold water (LSCW) as will be illustrated in the analytical model (We are still working on the analytical model). The LSCW will work as a wettability modifier only without reducing the oil viscosity. LSCW is not favorable for use in heavy oil reservoirs because the sweep efficiency is very low due to density differences unless the LS water chemistry is manipulated; however, contact angle measurements showed that the LSCW altered the sandstone wettability towards the neutral wet condition.
Ortiz-Volcan, J. L. (Kuwait Oil Company) | Ahmed, K. (Kuwait Oil Company) | Azim, S. (Kuwait Oil Company) | Issa, Y. (Kuwait Oil Company) | Pandit, R. (Kuwait Oil Company) | Al-Jasmi, A. K. (Kuwait Oil Company) | Hassan, M. O. (Kuwait Oil Company) | Sanyal, A. (Kuwait Oil Company) | Taduri, S. (Kuwait Gulf Oil Company)
Selecting the optimum combination of technologies is a critical and challenging activity while conducting the opportunity assessment under high levels of uncertainty in a deep ( 9000 feet) extra heavy oil green field transitioning between appraisal and development phases. Low mobility requires enhanced oil recovery to be addressed early in the life of the field, so selected wells can be drilled and completed in selected locations to reduce uncertainty about producibility and flow assurance. This paper presents a practical approach to opportunity assessment based on Front End Loading (FEL) methodology, with three major steps: 1. Evaluation of known data, determination of complexities, uncertainties and risks by benchmarking with selected field analogs, 2. Identification of all potential technology options and 3. Definition of feasible appraisal and development scenarios and a high-level road map including estimates of life cycle cost opportunities for optimization. We found reservoir static complexity medium, well complexity low, and reservoir dynamic complexity high. FEL definition indices for reservoir and well indicated low reservoir definition and acceptable index for wells.
This paper presents a practical method for benchmarking heavy oil fields as a tool for identification of opportunities for total cost and production optimization. The method combines actual data from typical heavy oil fields to define reservoir, well and surface complexity indices, for categorizing a subject field and a total cost breakdown model to map potential risks that could cause total cost to increase, potential project/ process delay and poor production performance. The benchmarking process consists of four steps: 1) classification of a subject field using Front End Loading (FEL) and complexity indices that account for: a) reservoir structural, stratigraphic, rock, fluid, energy, static and dynamic complexity, b) well complexity and c) surface processes complexity; 2) selection of analog fields within the range of indices; 3) use of causal maps to identify causes of uncertainty and risks that impact capital expenditures (CAPEX), operational expenditures (OPEX), production losses and cycle time; and 4) a total cost stochastic model is used to generate graphs providing the position of the subject field vs. analogs. A total undiscounted cost breakdown structure provided information on the most critical cost drivers, where significant impact corresponded to OPEX. Causal maps described typical total cost drivers for surface and subsurface.
Surfactin is an anionic surfactant generated by bacteria. Although it has high ability to decrease interfacial tension (IFT) between oil and water, it binds with bivalent cations and forms precipitation. Because the precipitation causes the significant reduction of reservoir permeability, surfactin cannot be applied to EOR in oil reservoir whose bivalent cations concentration is more than 100 ppm. This study investigated methods for applying surfactin to reservoir containing bivalent cations with high concentration.
Screening of an effective binding inhibitor was carried out by measuring turbidity of the solution containing 0.3 wt% of surfactin, 900 ppm of calcium ion, and inhibitor candidates such as alcohols, chelating agents, cationic surfactants, and ion capturing substances. Influence of the inhibitors on surfactin capacity for decreasing IFT was also evaluated by measuring IFT between the solution and oil. The best inhibitor was finally selected through the injectivity tests using Berea sandstone core which was saturated with calcium solution. EOR potential of the solution containing the inhibitor was evaluated by the core flooding experiments.
Citric acid and trisodium citrate inhibited binding of surfactin with calcium ion with lower concentration such as 0.6 wt%, they were selected as potential inhibitors and subjected to the IFT measurements. Both of them had strong potential as co-surfactants of the surfactin because IFT was greatly decreased to less than 0.1 mN/m which was less than a tenth as compared with IFT between the pure surfactin solution and oil. Trisodium citrate however caused significant permeability reduction on the injectivity tests whereas citric acid could be injected into the core without permeability reduction. The high pH value of trisodium citrate solution might cause the dissolution of ferrum and aluminum in the core and the colloids of ferrous hydroxide and aluminum hydroxide were formed in the core, which brought the significant permeability reduction. Citric acid was selected as the best inhibitor and subjected to the core flooding experiments. 25 % of oil remaining after primary recovery was recovered by injecting the solution containing 0.3 wt% of surfactin, 0.6 wt% of citric acid and 900 ppm of calcium ion. Rise in the differential pressure was not found during the injection of the solution, which suggested that citric acid was effective for inhibiting the precipitation in oil reservoir. Moreover, 25 % of recovery factor was 5 % higher than the recovery factor obtained by injecting pure surfactin solution. Citric acid is also effective for enhancing the surfactin capacity for increasing the recovery factor.
Citric acid has dual role as the binding inhibitor and co-surfactant. Because citric acid is environmentally friendly and cheap chemical, it can be promising additive which increase the applicable reservoir and potential of surfactant EOR.
Varshney, Mayank (Cairn Oil and Gas, Vedanta Limited) | Goyal, Aman (Cairn Oil and Gas, Vedanta Limited) | Goyal, Ishank (Cairn Oil and Gas, Vedanta Limited) | Jain, Akanksha (Cairn Oil and Gas, Vedanta Limited) | Pandey, Nimish (Cairn Oil and Gas, Vedanta Limited) | Parasher, Arunabh (Cairn Oil and Gas, Vedanta Limited) | Vermani, Sanjeev (Cairn Oil and Gas, Vedanta Limited) | Negi, Anil Singh (Baker Hughes, A GE Company) | Sharma, Vinit (Baker Hughes, A GE Company)
Waterflood is most commonly used secondary recovery mechanism in conventional sanstone reservoirs worldwide. Waterflooding assists in pressure maintenance and increases the field estimated ultimate recovery (EUR). Conformance in water injector wells plays an important role during waterflooding of a reservoir. Better conformance results in improved vertical sweep efficiency leading to higher recovery.
Continuous injection of fluids into the reservoir at higher rates may create channels for preferential flow. Zones of higher permeability, leading to higher injectivity in selective zones, can also exist because of various lithological conditions and rock structures comprising of naturally occurring fractures or fissures. For injection wells, the entry of fluids into a set of perforations is governed by the quality of the perforations and the permeability of the formation at that depth. Preferential flow of injected fluids into selective pay intervals results in diminished overall sweep efficiency. (J. Vasquez, et.al., 2008).
This paper discusses the use of thermally activated gels from polyacrylamides and metal chelates applied for selective reservoir matrix permeability reduction in an injector well. A low concentration, low viscosity delayed crosslinker gel system employing partially hydrolyzed polyacrylamide (PHPA) exhibiting 12-14% degree of hydrolysis level with chromium acetate as crosslinker offering delayed gelation time was used to selectively isolate one of the payzones.
A non-profile retrievable (NPR) plug was installed to isolate the target interval from the rest of the pay zones to enable selective treatment of the interval using coiled tubing (CT). The fluid was customized to minimize CT friction while ensuring that the rheological properties of the fluid in the reservoir would achieve the desired diversion and allow delayed gel crosslinking mechanism assuring avoiding of gel crosslinking in CT while pumping in progress. Denser brine relative to the delayed gel density was spotted above the NPR plug to avoid gel settling on the plug for easy retrieval of the plug post-treatment. Injectivity was measured and subsequently, the treatment was placed as per design while constantly monitoring the pressures so as to qualitatively determine the effectiveness of the treatment placement.
The treatment resulted in significant alteration in injectivity of the targeted zone. Post-treatment production logs confirmed an improvement in the injection conformance. Later, the zone was isolated and the bottommost zones were selectively stimulated enhancing the injection and thus improving sweep efficiency. Since the crosslinked gel system is not prone to any disintegration when in contact with acidic interventions, the treatment ensures a superior longevity of the conformance control when compared to other conventional diversion or zonal shut-off treatments.
The success of the treatment substantiates that the CT deployed low viscosity, low concentration delayed crosslinked gel system application can be successfully extended to selective water shut-off applications in producer wells. The injector profile modification treatment executed offered a comprehensive solution to conformance issues enhancing volumetric sweep efficiency, pressure maintenance across depleted sands and avoiding further water cycling in producer wells.
Reservoir modeling and the derived fluid production over time curves are a key part of the workflows associated with major capital project decisions. These models may be very complex and use a variety of geological constraints in an effort to develop the porosity, permeability, and saturation distributions used in dynamic models (with or without upscaling). Over time and partially in response to increased computing capability as well as the need for more realistically heterogeneous models, model size as measured by number of model cells and model complexity has increased but model-derived production forecasts remain optimistic. This paper, one of a series that now stretches back over a decade, addresses a number of modeling issues with the goal of (1) better understanding how modeling workflows may contribute to forecast optimism and (2) what reservoir modelers, both geologists and engineers, may do to reduce forecast optimism derived from their subsurface models by improved understanding of how model parameters such as grid size, number of grid cells, semivariogram parameters (e.g. the range), and number of geological/stratigraphic "control" surfaces used to constrain models. Adequate modeling of reservoir heterogeneity appears to require very to extremely large models (e.g. large number of small cells). Many of the parameters used to "control" heterogeneity including the semivariogram range parameter, the number of "detailed" stratigraphic layers, and the number of rock/facies "containers" or model regions appears to have only a small impact on forecast recovery.
The objective of the study is to determine the main mechanisms for sand production and to propose completion designs to minimize sand production for HPHT gas wells in the Tarim Basin. Sand production has been a very serious concern in these HTHP gas wells. This paper presents field results for several key wells which are prone to sanding and investigates the possible reasons and mechanisms responsible for sand production. A fully coupled 3D, poro-elasto-plastic sand production model has been developed and applied to study sand production issues for these wells. Sand production data from several wells were analyzed to better understand the conditions under which sand production occurs and conditions under which it is mitigated.
The sand production model was used to model the different completion designs and flow back strategies that were used in the field. The model couples multi-phase fluid flow and elasto-plasticity to simulate pressure transient and rock deformation during production. The sanding criterion is a combination of both mechanical failure (shear/tensile/compressive failure) and fluid erosion. A novel cell removal algorithm has been implemented to predict the dynamic (time dependent) sand production process. In addition, the complex geometry of the wells and perforations are explicitly modeled to show cavity propagation around hole/perforations during sand production.
For this study, triaxial tests on core samples have been conducted and the stress-strain curves under different confining stresses are analyzed to obtain rock properties for both the pre-yield and post-yield period. The wells were categorized into ones that had massive sand production and ones that showed much less sand production. Operational and mechanical factors that were empirically found to result in sand production were identified. The sand production model was run to verify the role played by different factors. It is shown that completion design, rock strength and post failure behavior of the rock are key factors responsible for the observed sanding in these wells. In addition, the drawdown strategy and the associated BHP change and the extent of depletion play an important role in the sanding rate. Several strategies for minimizing sand production are suggested for these wells. These include, drawdown management, completion and perforation design. In this study, we quantitatively show for the first time that data from HPHT gas wells that suffer severe sand production problems can be modeled and analyzed quantitatively to determine the mechanisms of sand production. This allows us to make operational recommendations to minimize sanding risk in these wells.
Sun, Zhuang (The University of Texas at Austin) | Tang, Hewei (Texas A&M University) | Espinoza, D. Nicolas (The University of Texas at Austin) | Balhoff, Matthew T. (The University of Texas at Austin) | Killough, John E. (Texas A&M University)
The reduction of pore pressure caused by depletion can induce significant reservoir compaction, especially in unconsolidated reservoirs. Experiments using unconsolidated core samples are often sparse and costly. We develop a numerical approach based on computer-based simulations of rock samples and mechanical tests. The numerical sample consists of crushable grains simulated with the discrete element method (DEM) and the bonded-particle model (BPM). Model parameters are calibrated through numerical single-grain-crushing tests which reproduce the experimentally-measured sand strength. Grain crushing induced by the uniaxial strain stress path results in a pronounced reduction of porosity and permeability, which manifests more readily for samples with large grain size. The change of particle size distribution indicates that the high effective stress causes grain crushing and produces a significant amount of fines. We perform numerical uniaxial strain tests on numerical samples comprising stiff and soft mineral grains. Simulation results indicate that the presence of soft grains and inclusions (e.g. shale fragments) facilitates the grain crushing. Reservoir simulations, incorporating the change of porosity and permeability as a compaction table, show that the upscaled compaction can enhance production due to compaction drive but also reduces production rate by impairing the reservoir permeability. This multiscale numerical workflow bridges particle-scale compaction behavior and field-scale reservoir production. In this paper, (a) DEM simulations provide a useful tool to investigate compaction effects and complement laboratory experiments; (b) the multi-scale numerical approach can predict the depletion-induced evolution of reservoir production.
This study is based mainly on the Cubagua formation belonging to the Dragon field, where the intervals of interest of the deposits are poorly consolidated and the cementation of the grains of sand is poor, as to be able to withstand the efforts applied as a result of the passage of the produced fluids through them, being able to start the phenomenon of sandblasting. The realization of this work consisted of the use of the BP-Willson methodology