Maximizing production from brownfields and extending the plateau have become utmost priorities for exploration-and-production companies the world over. Many papers presented during the past year at SPE conferences and surveyed for this review address these issues. Infill drilling and optimization of ongoing waterflood are two activities planned for revitalization of mature fields. Drilling through differentially depleted, multilayered reservoirs and the untapped deeper zones is a challenging task. Robust knowledge of rock properties, formation pressures, magnitude of in-situ stresses, and their evolution with production and depletion is essential for successful drilling of new wells in the redevelopment of mature fields.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Drilling and completion of long, highly deviated or horizontal wells have become normal in most of the mature petroleum reservoirs, especially for unconventional plays.
Pandey, Ajeet Kumar (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Kumar, Vishwa (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Bharsakle, Anuradha (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Vasudevan, K. (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Singh, Dhruvendra (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited)
Quantification of uncertainty in input parameters to build a robust 3D geological model is an integral and perhaps the most crucial requirement in high-risk exploration areas. This demands more innovative and effective management of uncertainties for optimizing reserve portfolios and better formulation of exploration and exploitation strategies for oil and gas fields. The present area of study pertains to Mumbai/Western Offshore Basin of India. The reservoirs of the study area are challenging due to their high spatio-temporal heterogeneity and discrete fluid distribution. Wells drilled during the field development plan are devoid of hydrocarbon from the lower zone of the reservoir (Middle Eocene/lower Bassein pay) while upper zone (Late Eocene/upper Bassein pay) produced significant amount of gas despite same lithological composition and structural setup, which reduced the utility of pressure-performance based or conventional modeling approach as it couldn't explain the complex geological set up of the deposition.
In this background, a thorough evaluation of critical aspect of most complex and anisotropic carbonate reservoir of Bassein Formation of Middle to Late Eocene age has been taken up to delineate the trends of favorable locales in the area. Inputs from micro-facies analysis, fluid transmissibility of Formations and diagenetic imprint analysis were considered to start the present study. An integrated methodology was designed incorporating seismic, well/logs, core samples, sedimentological, bio-stratigraphic & reservoir data to estimate petrophysical properties and necessary modifications in conventional approach were introduced for capturing the reservoir heterogeneity and stochasticity. Hi-frequency digenetic cycle mapping at log scale and pre-stack inversion results (P & S impedance, Vp/Vs ratio) were incorporated to build a robust geo cellular model and characterize the reservoir.
Uncertainty analysis presented in this study is mainly focused on structural and petrophysical parameters. The effect of each parameter/factor and their interaction effect (response) with other parameters are analyzed through Optimization Algorithms, to quantify the uncertainties and its impact on reservoir characterization. Sensitivity analysis indicated that Oil Initially In Place (OIIP) exhibits significant sensitivity to effective porosity and water saturation. Therefore, distribution pattern of these uncertainty parameters are derived from Probability Density Function (PDF) and used to restrict the variability of the volumetric estimates to retain the P10/P90 ratios within the acceptable ranges.
Quantification of structural parameter was performed using non-linear multiple regression technique, constrained by statistically Maximum Allowable Error (+Standard Deviation).
Present analysis enabled us to reduce the uncertainty associated with various reservoir characterization elements. Further, it enhanced robustness of velocity modeling, petrophysical and lithological interpretation through determination of uncertainties with high degree of accuracy and provided their role in estimation of final hydrocarbon-in-place volumes. The parameterization of the uncertainties deliberated could be used as a template in other fields sharing similar structural and depositional characteristics to mitigate the risks associated with Field Development Plan.
The basal clastic sand (BCS) unit is derived from a granitic basement and forms the lower part of the Mumbai High field. Oil indicators in unconventional reservoirs, such as basement and BCS, were explored here before 1987; however, these reservoirs were not targeted for more than two decades after drilling the first exploratory well in 1989. Huge potential in BCS resources remained untapped, and monetizing these resources became possible because of extensive hydraulic fracturing design optimization for these layers.
Previously, acid stimulation treatment failed to provide any improvement in the BCS reservoir. Because BCS is derived from a granitic basement and contains clay minerals (kaolinite and chlorite), heavy minerals, siderite, pyrite, hematite, etc., it is difficult to obtain gains using acid stimulation because of poor leakoff and associated reaction kinetics. However, stimulation using hydraulic fracturing with proppants proves to be the ultimate productivity enhancement tool and is the prudent alternative.
The first hydraulic fracturing attempt in BCS was performed at Well B in 2013 and was unsuccessful because proppant placement and admittance are extremely difficult in these layers. High net pressure and complex branch growth were identified to be the core causes of premature screenout in this layer. Post-treatment pressure evaluation indicated propagation of short fissures and fractures leading to a complex fracture plane that reduced overall fracture conductivity.
Subsequently, Well A was diverted from the original location, completed in the BCS reservoir, and selected as a candidate for proppant fracturing. The stimulation strategy was designed to meet stimulation challenges of the BCS formation. Perforation designs were revised to reduce near-wellbore tortuosity and perforation friction. After perforating, the well was treated with an acetic acid cushion against the target zone. A new fracturing treatment design based on slug and sweep, where the slug stages were increased, was used to control excessive near-wellbore complex fracture growth. Aggressive pumping rates and high conductivity proppant size and concentration were designed to help increase stimulation efficiency. These unconventional modifications aided successful placement of the fracture plane in the BCS reservoir in Well A.
Well A initially produced 202 BOPD; however, production declined because of the tight nature of the BCS reservoir. Later, the well produced 100 BOPD with gas lift. After hydraulic fracturing treatment for this well was successfully performed, as per the modified design, the production increased to 1,580 BLPD with 100% oil and no artificial lift using a 1/2-in. choke. This paper highlights design considerations, execution results, and post-treatment evaluation of this extremely challenging BCS volcanic rock and can be viewed as a best practice for addressing stimulation challenges in similar volcanic reservoirs in other fields.
With known basement hydrocarbon accumulation, Mumbai High field in Western Offshore, India is a priority area for extending the concept of fracture characterization in metamorphic basement reservoirs. Basement in Mumbai High is hydrocarbon bearing in few areas proximal to major fault damage zones and intersections of major regional tectonic cross trends. The challenge lay in characterizing such basement reservoirs with significant heterogeneities in mineralofacies, in situ stress fields, seismic amplitudes, fracture properties and connectivity, and flow potential. This necessitated development of an integrated static fracture model workflow assimilating structural modeling, seismic and petro-physical interpretations for fracture drivers and geocellular fracture modeling, fine tuned using geological concepts and point data extracted from well data analyses. The deterministic geo-cellular fracture model thus prepared has been calibrated with real time well observations and has been found to satisfactorily explain anomalous hydrocarbon accumulation and flow pattern in basement wells tested in the area. The adopted workflow has helped planning wells for evaluating and exploiting basement reservoir as well for real time monitoring of wells.
Thapliyal, Anil (Oil and Natural Gas Corporation Ltd.) | Kundu, Sudeb (Oil and Natural Gas Corporation Ltd.) | Dimri, Sunil Kumar (Oil and Natural Gas Corporation Ltd.) | Dutt, Ankit (Schlumberger) | Mishra, Shubham (Schlumberger) | Aggarwal, Akshay (Schlumberger) | Agarwal, Ankit (Schlumberger) | Ojha, Aditya (Schlumberger) | Bradley, David (Schlumberger) | Giddins, Marie Ann (Schlumberger)
For planning the operations of Oil and Natural Gas Corporation Limited (ONGC) in the complex Heera field, it was estimated that over one hundred simulation runs would be needed to complete the history match of the field and almost the same number of simulations would be needed for production forecasting. Heera is a large field, with multiple faults and seven stacked carbonate formations. There are significant variations in petrophysical properties, and variable degrees of communication between reservoir zones. The simulation models include 479 wells with commingled production or injection. Well trajectories are complex and include multilateral and horizontal configurations. Field development options include use of simultaneous water alternating gas (SWAG) for enhanced oil recovery.
Combining all these features, it would be difficult to run all the necessary sensitivity cases within the required project timeline, using a conventional reservoir simulator. Therefore, it was decided to test the applicability of a new generation simulation tool to address the challenges of the study.
To ensure that the change of simulator would not impact the integrity of the model, rigorous quality checks were performed on the input data. After successful evaluation, the new software was used for the reservoir engineering study.
The decision to apply the new simulator significantly reduced the elapsed time, with some realizations over 20 times faster compared to the original base case. As a result of this speed-up, numerous runs could be carried out to refine the history match. Multiple sensitivities could be used to help understand and reduce the uncertainties in a more comprehensive manner. Moreover, the prediction cases could be optimized to identify the best recovery strategy.
This study has demonstrated the value of reducing simulation run times, to complete the project with greater efficiency and more confidence in the results. In future studies, high performance software tools can also enable use of fine resolution models, to capture detailed heterogeneities and optimize areal and vertical sweep.
Li, Lei (University of Alberta) | Ma, Yongsheng (University of Alberta) | Mahmoudi, Mahdi (RGL Reservoir Management) | Fattahpour, Vahidoddin (RGL Reservoir Management) | Lange, Carlos F. (University of Alberta)
Effective steam distribution in the injector is the key to achieve efficient and uniform reservoir heat up in SAGD operation. The focus of this research is on simulating the flow dynamics in outflow control device (OCD), the annular space between the liner and tubing, the slots, and the gap between the slotted liner and formation, using computational fluid dynamics (CFD). The objective is to use the approximated metamodel to optimize the OCD design and achieve more even steam distribution through the slots.
A CFD model of the steam is developed through a systematic investigation of different domain sizes to study the effect of the pressure drop across the nozzle and the steam distribution. An evenness factor is proposed to quantify the overall steam distribution and to identify problematic slot areas. Based on the developed model, the OCD design is simplified and parameterized to conduct optimization efficiently. With the CFD expert system for steam simulation, the robust simulation models corresponding to different designs are obtained, providing accurate simulation results to the optimization algorithm. Using metamodeling, the response to the five design variables is derived, and the optimum is obtained subsequently. A cylindrical region representing the vicinity of the liner is added to the periphery of the slots to translate the optimization results into the realistic design.
The CFD simulation and OCD design optimization show that the steam distribution is highly controlled by the OCD design, mainly by the nozzles’ distance to the central plane. The novel evenness factor provides a quantitative assessment of the effect of design changes and it enables the application of advanced design optimization algorithms. Fifty-five numerical experiments are conducted to obtain the relationship between the proposed evenness factor and the design variables. The overall design of the OCD can be fine-tuned to account for the steam distribution. At the beginning of the heating cycle, some flow reversal is found in some specific slots, which may lead to sand production, plugging and erosion. When the distance between the two sets of nozzles is extended to 50 mm, the normalized evenness factor shows that the steam distribution can be improved by 12.5% from the original design in which the distance used to be zero. Moreover, the velocity magnitudes in the reverse flow affected region are also reduced in the optimized design.
The CFD simulation is a powerful tool to understand the flow dynamics through OCDs. This study applies a robust CFD model to investigate the complex flow interactions that affect steam distribution through OCDs to improve their design and thus to improve the steam distribution. The provided model and the design optimization algorithm could ultimately improve the heating efficiency.
Maximizing production from brownfields and extending the plateau have become utmost priorities for exploration-and-production companies the world over. This calls for a synergistic approach involving close coordination of various disciplines—subsurface, surface, well drilling and completions, and facilities engineering—to achieve the common goal of maximizing production and recovery. There is a growing awareness that maximizing field production involves not only having a clear understanding of subsurface intricacies but also ensuring that existing surface facilities are performing at their best to handle production in an environmentally safe manner. Many papers presented during the past year at SPE conferences and surveyed for this review address these issues. Infill drilling and optimization of ongoing waterflood are two activities planned for revitalization of mature fields.
Maximizing production from brown-fields and extending the plateau have become utmost priorities for exploration-and-production companies the world over. This calls for a synergistic approach involving close coordination of various disciplines—subsurface, surface, well drilling and completions, and facilities engineering—to achieve the common goal of maximizing production and recovery. There is a growing awareness that maximizing field production involves not only having a clear understanding of subsurface intricacies but also ensuring that existing surface facilities are performing at their best to handle production in an environmentally safe manner. Many papers presented during the past year at SPE conferences and surveyed for this review address these issues.
Infill drilling and optimization of ongoing waterflood are two activities planned for revitalization of mature fields. Drilling through differentially depleted, multilayered reservoirs and the untapped deeper zones is a challenging task. Robust knowledge of rock properties, formation pressures, magnitude of in-situ stresses, and their evolution with production and depletion is essential for successful drilling of new wells in the redevelopment of mature fields. It is necessary to apply several tools to identify locations of bypassed oil and corroborate the findings of these tools before making a final decision. This becomes even more challenging when there is low resistivity contrast, such as in freshwater environments or in certain cases where openhole logging is not possible because of poor borehole conditions. Operators have calibrated numerical-simulation models successfully with innovative logging tools to locate and produce new oil from old fields.
Rejuvenation of mature assets plays a crucial role in the current low-oil-price scenario, allowing for improved production with limited investments and risks. Nevertheless, brownfield rejuvenation is often very demanding in terms of complex integrated reservoir studies, which typically take several months to complete. The new and emerging technology of applying analytical and data-driven models provides fast solutions to diagnose ongoing waterflooding processes effectively and examine low-cost strategies to improve areal- and vertical-sweep efficiencies.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 184902 Effects of Pressure Depletion on Stress-Field and Casing-Load Alteration in Mature Fields: A Case Study by Peng Zhang, Halliburton, et al.
SPE 185412 Effective Waterflood Management in Complex Carbonate Reservoir of Mumbai High Field by N.T. Ravi, ONGC, et al.
SPE 186004 Developing Infill and EOR Opportunities While Managing Subsurface Uncertainties in a Mature Complex Field Using Probabilistic Dynamic Modeling by R. Abd Karim, Petronas, et al.