The current scheme for developing shale reservoirs necessitates special considerations while estimating the reserve. While reservoir characteristics lead to an extended infinite acting flow regime, completion schemes could result in a series of linear flows. Therefore, the initial linear flow does not have to be followed by a boundary-dominated flow. Overlooking this observation leads to unphysical Arps’ exponents and overestimations of the Estimated Ultimate Recovery (EUR). We are proposing a workflow to overcome these challenges and honor the inherited uncertainty while using the classic
Amer, AimenAi (Schlumberger) | Sajer, Abdulazziz (Kuwait Oil Company) | Al-Adwani, Talal (Kuwait Oil Company) | Salem, Hanan (Kuwait Oil Company) | Abu-Taleb, Reyad (Kuwait Oil Company) | Abu-Guneej, Ali (Kuwait Oil Company) | Yateem, Ali (Kuwait Oil Company) | Chilumuri, Vishnu (Kuwait Oil Company) | Goyal, Palkesh (Schlumberger) | Devkar, Sambhaji (Schlumberger)
Producing unconventional reservoirs characterized by low porosities and permeabilities during early stages of exploration and field appraisal can be challenging, especially in high temperature and high pressure (HPHT) downhole conditions. In such reservoirs, the natural fracture network can play a significant role in flowing hydrocarbons, increasing the importance of encountering such network by the boreholes.
Consequently, the challenge would be to plan wells through these corridors, which is not always easy. To add to the challenge, well design restrictions dictate, the drilling of only vertical and in minor cases deviated wells. This can reduce the possibility of drilling through sub-vertical fracture sets significantly, and once seismic resolution is considered, it may seem that all odds are agents encountering a fracture network.
This article addresses a case where a vertical well is drilled, in the above-mentioned reservoir setting, and missed the natural fracture system. The correct mitigation can make a difference between plugging and abandoning the well or putting it on production.
The technique utilized is based on a borehole acoustic reflection survey (BARS) acquired over a vertical well to give a detailed insight on the fracture network 120 ft away from the borehole. Integrating this technique with core and high-resolution borehole image logs rendered an excellent match, increasing the confidence level in the acoustically predicted fracture corridors.
Based on these findings new perforation intervals and hydraulic stimulation are proposed to optimize well performance. Such application can reverse the well decommissioning process, opening new opportunities for the rejuvenation of older wells.
Skalinski, Mark (retired Chevron ETC) | Mallan, Robert (Chevron ETC) | Edwards, Mason (Chevron ETC) | Sun, Boqin (Chevron ETC) | Toumelin, Emmanuel (Chevron ETC) | Kelly, Grant (Chevron ETC) | Wushur, Hazaretali (Chevron ETC) | Sullivan, Michael (Chevron Canada Resources)
Assessment of the “net pay” is an essential part of reservoir characterization and resource determination. Standard methods usually involve the use of porosity, permeability and water saturation cutoffs to define net reservoir, net pay and perforation zones. However, there are no industry standards for the definition of cutoffs and their application in the reservoir characterization workflows. Assessment of net-pay cutoff s in carbonates is more challenging than in clastics due to inherent heterogeneity of pore architecture and permeability. Historically, the success rate of flowing perforations is low, and operators tend to “overperforate” to capture all potential flowing zones.
This study was undertaken to redefine pay categories and provide methods of cutoff determination in carbonates, leveraging applications of NMR logging, capillary pressure, and in-situ flow measurements. The new category of “gross hydrocarbon” is introduced to describe the rock charged with hydrocarbon. The new methods defining “gross hydrocarbon” are described: NMR shape analysis and hydrocarbon-charged pore-throat (HCPT) or R10 method. NMR T2 shape and 2D shape analyses define the minimum porosity and/or permeability with detectable hydrocarbon signal. The T2 shape analyses were performed for several carbonate fields around the world, yielding a porosity cutoff for hydrocarbon charge varying between 1.5 and 3.5%, depending on reservoir type.
The HCPT or R10 method used an extensive MICP dataset from these carbonate fields to predict an entry pore-throat radius corresponding to potential hydrocarbon charge. The predicted entry pore-throat log combined with the pore-throat size corresponding to capillary pressure at specific height above free-water level (HAFWL) allowed to define zones which were not penetrated by hydrocarbon charge due insufficient capillary pressure. Definition of those zones corroborated results from the NMR shape analysis. Both methods are restricted to hydrocarbon column.
The next cutoff investigated was the minimum value of permeability associated with observed flow of in-situ fluids indicated by wireline pressure test or production logs. This cutoff would correspond to the conventional “net reservoir” definition. The use of permeability mitigates the need for porosity cutoff s, which usually vary by rock type. The study performed in the different carbonate reservoirs yielded permeability cutoff s varying between 0.01and 1 mD.
Practical examples from Tengiz, Karachaganak, PZ, West Africa and Permian basin validate the consistency between methods and the validity of statistical predictions of R10 pore throat. The methods presented here can be applied to any conventional reservoir.
Li, Boxiao (Chevron Energy Technology Company) | Bhark, Eric W. (Chevron Asia Pacific E&P Company) | Gross, Stephen J. (Chevron Energy Technology Company) | Billiter, Travis C. (Chevron Energy Technology Company) | Dehghani, Kaveh (Chevron Energy Technology Company)
Assisted history matching (AHM) using Design of Experiments (DoE) is one of the most commonly applied history matching techniques in the oil and gas industry. When applied properly, this stochastic method finds a representative ensemble of history-matched reservoir models for probabilistic uncertainty analysis of production forecast. Although DoE-based AHM is straightforward in concept, it can be misused in practice because the workflow involves many statistical and modeling principles that should be followed rigorously. In this paper, the entire DoE-based AHM workflow is demonstrated in a coherent and comprehensive case study that is divided in seven key stages: problem framing, sensitivity analysis, proxy building, Monte-Carlo simulation, history-match filtering, production forecast, and representative model selection. Best practices of each stage are summarized to help reservoir management (RM) engineers understand and apply this powerful workflow for reliable history matching and probabilistic production forecasting. One major difficulty in any history matching method is to define the history-match tolerance, which reflects the engineer's comfort level of calling a reservoir model "history-matched" even though the difference between simulated and observed production data is not zero. It is a compromise to the intrinsic and unavoidable imperfectness of reservoir model construction, data measurement, and proxy creation. A practical procedure is provided to help engineers define the history-match tolerance considering the model, data-measurement, and proxy errors.
Skalinski, Mark (Chevron) | Mallan, Robert (Chevron) | Edwards, Mason (Chevron) | Sun, Boqin (Chevron) | Toumelin, Emmanuel (Chevron) | Kelly, Grant (Chevron) | Wushur, Hazaretali (Chevron) | Sullivan, Michael (Chevron)
Assessment of net pay cutoffs in carbonates is more challenging than in clastics due to inherent heterogeneity of pore architecture and permeability. Historically, the success rate of flowing perforations is low, and operators tend to “over-perforate” to capture all potential flowing zones. Asset teams must assign net thicknesses for modeling and resources assessment. Simple porosity cutoffs which might be adequate for sandstones often fail in complex carbonates. This study was undertaken to assess definitions of cutoffs in carbonates, leveraging applications of NMR logging, capillary pressure, and in-situ flow measurements.
First, we looked at the cutoffs defining hydrocarbon charge into the pore system. Proper determination of this cutoff can help better estimate hydrocarbon in place. To address this question, we have developed NMR T2 Shape and 2D Shape analyses to define the minimum porosity and/or permeability with detectable hydrocarbon signal. The T2 shape analyses were performed for several carbonate fields around the world, yielding porosity cutoff for hydrocarbon charge varying between 1.5 and 3.5%, depending on reservoir type.
Second, extensive MICP data from these carbonate fields were used to predict an entry pore throat radius corresponding to potential hydrocarbon charge. The predicted entry pore throat log combined with the pore throat size corresponding to capillary pressure at specific height above free water level (HAFWL) allowed to define zones which were not penetrated by hydrocarbon charge due insufficient capillary pressure. Definition of those zones collaborated very well with results from the NMR Shape analysis, extending our ability to define “gross hydrocarbon” for fields without NMR data.
The next cutoff investigated was the minimum value of permeability that correlated with observed flow of in-situ fluids, i.e.: production logs, derivative of temperature logs, and wireline pressure tests. This cutoff would correspond to the conventional “net reservoir” definition. The use of permeability mitigates the need for porosity cutoffs which usually varies by rock types. We have predicted permeability from logs using the K-Nearest Neighbor method which reconstructs well the core permeability distribution. The study performed in the different carbonate reservoirs yielded permeability cutoffs varying between 0.01and 0.1 mD.
This approach allowed us to define a set of recommendations for definitions of net reservoir and net pay, and to provide a practical methodology to assess hydrocarbon potential. The methods presented here can be applied to any conventional reservoirs.
Morales, Victor Alfonso (Occidental de Colombia LLC) | Ramirez, Leyla Kristle (Occidental de Colombia LLC) | Garnica, Sandy Vanessa (Occidental de Colombia LLC) | Rueda, Luz Adriana (Occidental de Colombia LLC) | Gomez, Vicente (Occidental de Colombia LLC) | Gomez, Adriana (Occidental de Colombia LLC) | Bejarano, Maria Angelica (Occidental de Colombia LLC) | Shook, G. Michael (Mike Shook & Associates)
La Cira Infantas is the oldest oil field in Colombia with approximately 100 years of production history, located in the Middle Magdalena Valley Basin. The field production comes from the C zone reservoir of Mugrosa Formation where the depositional environment is a fluvial meandering system. The reservoir has a high heterogeneity and it is defined as an interbedding of sandstones, shales and siltstones with an average thickness of 600 ft and a permeability range from 80 mD to 2 Darcy. The field has been under secondary recovery since the 1960's and in 2005 a redevelopment of the water flooding process began. The field has approximately 400 patterns and 1,000 active producer wells, 95% of which are under a water flooding process. Injector wells have a selective string completion, composed of mandrels and packers, independently injecting in different sand units. Currently, there are patterns with low areal efficiency and consequently lower than expected recovery factor. An interwell tracer project was executed in a six pattern pilot sector, composed of 16 distinct mandrels, in order to validate the need of a conformance treatment to improve current conditions and have a better understanding of the reservoir connectivities. In each selected mandrel a unique tracer family was used in order to accurately intepret breakthough results.
The workflow in the project starts by using the results of the tracer test to estimate swept volume and flow geometry in all patterns. The swept zone represents the thief zone in each pattern and provides an insight of how poor the areal efficiency of the pattern is. Flow geometry is represented in an F- Φ curve and the tangent is related to the residence time of an arbitrary flow line, which is used to first recognize the need for a conformance job and then to calculate the fraction of the swept volume needed to treat. The last step of the workflow is to estimate the incremental oil production rates derived from treating the thief zone. Two analytic methods were derived for the incremental oil production rate estimates. The conformance candidates were ranked according to treatment volume vs. incremental oil recovered over a two-year timeframe. Those results are in process of being analyzed.
The results of the inter-well tracer showed that conformance is needed in 6 individual mandrels and there is a strong relationship between the facies architecture and the flow distribution of the injected water. Also, it will improve the definition of the job portfolio for the conformance project which considers 80 candidates and 2.7 MMBO resources.
The application of conformance treatments is a novelty in multilayer mature oil fields under water flooding process in Colombia, and the study of inter well tracers is essential for the success of this IOR technology.
Kumar, Raushan (Chevron Corp) | Socorro, Daniel (Chevron Corp) | Pernalete, Marta (PDVSA) | Gonzalez, Karin (Chevron Corp) | Atalay, Nilufer (Chevron Corp) | Nava, Rafael (Chevron Corp) | Lolley, Chris (Chevron Corp) | Kumar, Mridul (Chevron Corp) | Arbelaez, Alejandro (Chevron Corp)
Boscan is a giant multi-billion-barrels heavy oil (10.5° API gravity and asphaltic) field in Venezuela. Although, a large part of the field is on primary production with a low recovery factor (<6%), water injection has been successfully implemented in portions of the field for over 15 years with improved recovery. High mobility ratio waterflood (HMRWF) behavior and associated key production mechanisms obtained from detailed field data analysis and dynamic modeling are presented. A novel and unique infill configuration is also proposed to further improve recovery in this high (or adverse) mobility ratio environment.
Water injection in such heavy oil (10.5° API) was considered not effective by the industry previously, due to adverse mobility ratio. However, water injection for pressure maintenance (WIPM) was successfully implemented using a pattern configuration, pseudo 1-3-1 inverted 7-spot (an additional row of producer between conventional pattern rows). Field data and reservoir simulation models show increased reservoir pressure up to the second row of producers from the injector. The pressure support is utilized to significantly improve recovery using the unique configuration at low water cut. WIPM has already resulted in significant reserves addition. Current production from water injection areas is ~40 MBOPD (or ~ 47% field production).
However, it is estimated that because of high oil viscosity, a significant amount of oil remains bypassed in the WIPM area. An infill opportunity was identified from an integrated reservoir management study that included detailed WIPM data analysis and dynamic (mechanistic and full field) modeling. A unique infill configuration is proposed that conceptually uses the current injectors with an additional row of producers between the existing first and second row of the producers. This configuration has the potential to economically unlock millions of barrels of bypassed oil and significantly increase recovery in this prolific heavy oil field.
This study provides insights into HMRWF behavior evaluating relative impact of displacement vs. pressure. The unique and novel infill configuration can be used to improve recovery, a step vital to monetize this large resource in the low-price environment.
It was recently shown that anisotropic wormhole networks may arise from the acidizing of anisotropic carbonates. In openhole or cased and densely perforated completions, where in isotropic formations the wormhole network would be expected to be radial around the well, the actual stimulated region may be elliptical in anisotropic formations. Analogously, in completions where the limited entry technique is used, the wormhole network is expected to be spherical in isotropic formations, but it may actually be ellipsoidal in anisotropic formations. That has an impact on the well performance and should be taken into account when designing the acidizing treatment and the completion. At the same time, the use of a limited entry technique may result in better stimulation coverage and also longer wormholes, but it may also result in a partial completion skin factor, impairing the productivity from the stimulated well. This should be taken into account when estimating the stimulated well productivity.
In this study two main topics are analyzed: the impact of wormhole network anisotropy and the impact of a limited entry completion. Both radial and spherical wormhole propagation patterns are considered, to be applied in both openhole and limited entry completions. The differences in well performance is studied for each case, and analytical equations for the skin factor resulting from each scenario are presented.
The anisotropic wormhole networks are obtained from numerical simulations using the averaged continuum model, and the results are validated with experimental data. The analysis of the well performance is made through simulation of the flow in the reservoir with the different stimulated regions.
The results show that for highly anisotropic formations the wormhole network anisotropy may have a great impact on the acidized well performance and this should be taken into account in the acidizing treatment design. It was observed that the anisotropic wormhole networks present lower productivity than equally sized isotropic stimulated regions. Hence, equations like Hawkins formula should not be used for estimating the skin factor from anisotropic wormhole networks, and the equations proposed in this work should be used instead.
Specifically, the impact of anisotropic wormhole networks is large when the limited entry technique is used. It is shown that for this type of completion there is an optimum stimulation coverage of about 60 to 70%, and the perforation density required to obtain for a given acid volume depends strongly on the wormholes' anisotropy. The skin factor equations proposed in this work for the stimulation with limited entry completion should be used for obtaining the optimum perforation density for a given scenario.
Tengizchevroil (TCO) is the biggest operator in Kazakhstan developing two world's deepest supergiant oilfields - Tengiz and, its satellite field, Korolev. With over 20 years of oil production at TCO, reservoir pressure has been declining and is approaching bubble point pressure. In order to arrest the declining pressure trend and extend oil production plateau, TCO is evaluating Improved Oil Recovery (IOR) opportunities, including potential Waterflood in Korolev field.
Accurate Waterflood evaluation requires improved characterization of the main uncertainties impacting ultimate recovery under IOR processes. Therefore, we built next-generation Korolev reservoir model (SIM15K) which incorporates results of the latest characterization efforts based on the latest wide- azimuth 3D seismic survey. This work led to updated Korolev depositional model, which helps to understand the links between geological settings and fracture occurrence. In conjunction with the first implementation of Dynamic Data Integration workflow, this resulted into updated Low-Mid-High fracture models - one of the main factors controlling Waterflood performance in naturally-fractured reservoirs.
This paper focuses on Brownfield Experimental Design (ED) of Korolev field, which is specifically designed to provide an estimate of IOR Incremental Recovery. We identified 23 main uncertainty parameters for each Low-Mid-High Fracture models. The Brownfield ED was run with two development scenarios: Primary Depletion and Waterflood to get probabilistic assessment of Incremental Waterflood Recovery. Overall 803 cases were required for each fracture model and development scenario to generate good quality proxies for cumulative recoveries and History-Match error. Those proxies were used to sample the entire space of uncertainties and define P10/50/90 targets.
As a result of robust Brownfield ED, we selected P10/50/90 models to capture both range in Incremental Waterflood Recovery and Ultimate Recovery under Primary Depletion. The underlying uncertainty parameters for the final model selection were picked based on their relative impact on the objective functions. Currently, the new SIM15K model is being used for Korolev Waterflood evaluation and optimization, Reserves estimation, existing infrastructure optimization and future projects design.
Unconventional reservoir development involves extensive hydraulic fracturing to create a Stimulated Reservoir Volume (SRV) connected to the wells, which will drive both the well productivity and associated development strategy. Once a well is hydraulically fractured, the next step is to clean it up by flowing it back to remove water from the wellbore and adjacent fracture network before putting it on production.
Currently, characterization of Multi-Fractured Horizontal Wells (MFHW) productivity is commonly performed with Rate Transient Analysis (RTA) of online production data after a significant production history, which also provides some indication of the SRV geometry. One of the main challenges today is to characterize the SRV geometry and productivity as early as possible and at the lowest cost possible.
Recent studies have demonstrated a valuable opportunity to gain information from early fluid production and flowing pressures gathered during the flowback operation that can be used to assess long-term well productivity; however such information is rarely exploited quantitatively. Several uses of flowback data include: completion design and flowback sequence optimization, choke strategy adjustment, SRV characterization and production forecasting.
Clarkson and Williams-Kovacs introduced a pseudo-analytical model for analyzing two-phase flowback to estimate key hydraulic fracture and reservoir properties, notably fracture half-length and conductivity. The base model assumes cylindrical fracture tanks in which three flow regimes occur: (1) transient radial flow of water within the fracture, (2) fracture depletion (boundary dominated flow of water while fracture pressure remains above formation pressure), and (3) coupled formation linear flow and multi-phase fracture depletion after formation fluid breakthrough (when fracture pressure drops below formation pressure). They established that Before Breakthrough (BBT) single-phase RTA and analytical modeling can provide an estimation of frac properties BBT and ABT.