This paper discusses an optimum approach to design and execution of a robust chemical enhanced oil recovery (EOR) surveillance program considering the physics and uncertainties involved during the implementation of a chemical EOR (CEOR) application at reservoir scale. The surveillance includes techniques, measuring points, and frequency of data acquisition. Based on field experience, a robust surveillance plan plays a key role in ensuring high performance of a CEOR application during implementation and execution at reservoir conditions. A proper surveillance program should focus on acquiring information associated with the main uncertainties related to fluid-fluid and rock-fluid interactions, the impact of reservoir heterogeneities at reservoir scale, fluid dynamics, and the composition and stability of the chemical formulation. The acquired information should be given to the CEOR modeling team to follow up, interpret, and adjust the CEOR process and reservoir model. Also, the information should be given to the reservoir operation team to tune up the CEOR injection and production process to help optimize performance. Typically, specialized literature focuses on describing CEOR formulation design and evaluation; laboratory requirements, experimental settings, and analysis results; field application design and implementation; and overall results of field applications. This work emphasizes CEOR process surveillance, its importance, and impact with respect to oilfield scale applications. There are multiple uncertainties regarding the physical parameters and phenomena that control the performance of the CEOR at reservoir scale (e.g., are uncertainties associated with fluid saturation and properties, rock-fluid interactions, reservoir heterogeneities, and alkali-surfactant-polymer (ASP) formulation behavior at reservoir conditions). A proper surveillance design and implementation help mitigate the impact of the mentioned uncertainties. Therefore, surveillance is paramount for the success of a CEOR application. The design and execution of a robust surveillance program should consider the main uncertainties associated with the CEOR formulation operating window, fluid-fluid and rock-fluid interactions, reservoir heterogeneities, reservoir conditions, injection-production environment, and various time scales for the timely use of the acquired information and the interpretation feedback to the CEOR modeling and operation teams. This work discusses the physics and uncertainties considered during the design and execution of an optimized surveillance program. A systematic approach is provided considering fluid-fluid and rock-fluid interactions, reservoir heterogeneities, CEOR formulation operating window, injection – production environment, and time scales to feedback the acquired and interpreted information during the surveillance program execution.

Flowback of wells after hydraulic fracturing has always been under debate because the future performance of fractured hydraulic wells depends on the operational procedure applied during the flowback. Unconventional reservoirs have become increasingly important hydrocarbon resources to develop and produce for the oil and gas industry, and the best cost-efficient approach to develop and produce unconventional reservoirs is by drilling and completion of horizontal multi-stage hydraulic fractured wells. Hence the complexity of the phenomenology seen during the flowback of this type of wells has increased substantially. The complexity of the phenomenology is the result of the change on the range of fluid and fluid-rock properties. The permeability of unconventional reservoirs is typically in the range of nano to low micro darcies. This implies that the forces acting on the fluid flow through the medium are extremely magnified. This paper is aimed at describing the phenomenology during early fluid flow in unconventional wells, and its relevance during the design, planning, and execution of well flowback. The work considers actual data and information of flowback in unconventional wells from the available literature, as well as our own experiences. The authors use this available data and information to describe the physical phenomena that occurs in unconventional wells, especially in the early stages of production testing. The paper describes a theoretical approach that explains the fluid behaviour seen during multi-stage hydraulic fractured unconventional wells. Finally, the flowback is characterized based on the phenomenology, and its description provides an approach to an improved design of well flow management. The characterization of the phenomenology during flowback allows us to identify six stages of fluid flow in unconventional wells during the early flow process. Each stage has been identified considering the acting forces, fluid flow, and implications during the flowback. After such description, flowback design is explained based on the phenomenology characterization. Finally, the authors provide a comparison of the design and the actual behaviour for the early stages of flowback. This work introduces an approach based on the characterization of the phenomenology associated to multi-stage hydraulic fractured unconventional wells that have been successfully applied in flowback operations. A comparison between theoretical designs and actual cases confirms the value of the methodology.

Relative permeability is an essential parameter for reservoir description, engineering, and management. Relative permeabilities are typically obtained in the laboratory through evaluation of the dynamic behavior in cores using fluids that are assumed to be representative of those in the reservoir. In-situ measurements of effective permeability can provide valuable information about fluids, rock, pressure, temperature, and their interactions in the evaluated formation at original reservoir conditions. Recent technological advances allow data obtained from formation testers to be analyzed and interpreted for estimating relative permeabilities. Formation testers are typically run when wells are drilled; therefore, using acquired data for estimating effective permeability can be cost-effective and less time-intensive compared to existing effective permeability estimation methodologies. However, the measurement process, the meaning of the acquired data, the interpretation of the data, and the resulting relative permeability values are affected by the uncertain environment associated with the entire process, which also affects the confidence of the estimated relative permeabilities and their use as an input for reservoir description, engineering, and management. Although the use of formation testers as a tool to estimate relative permeabilities is promising, it is crucial to understand the environment in which the dynamic events occur and the impact of the uncertainties related to the physical phenomena and interactions associated with the measurement and interpretation processes. Conversion of the acquired information at the oil/gas well into inputs to properly interpret the acquired data, the models available to interpret the phenomena, and the formation tester tool capabilities all require understanding of the uncertainties associated with the entire process. These uncertainties, when properly qualified and quantified, can serve as the decision criteria to estimate the value of information (VOI) of relative permeability determination using in-situ formation tester data. This work provides a detailed description of the uncertainties related to relative permeability estimation based on in-situ measurements of formation testers and its impact on the interpretation outputs.

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Rock typing in carbonate reservoirs has always represented a difficult challenge due to rock heterogeneity. When interpreting electrical logs, the thick carbonate formation can leave an impression of a homogenous environment; however, looking at core analysis and mercury injection capillary pressure (MICP) data, reservoir heterogeneity can be determined. This complexity of the formation characterization presents challenges in reservoirs that contain tilted water/oil contact (WOC). Tilted WOC discovers hydrocarbon saturation below the free-water level, and different events during geological time can contribute to this specific fluid accumulation. Knowledge of the fluid distribution is needed to understand the mechanisms of oil entrapment, oil volumetrics, and potential recovery mechanisms involved in reservoirs under this wettability and WOC conditions. This case study will describe the workflow used to characterize and model an atypical regime like non-water wet formations in reservoirs with tilted WOC. In this study, a combination of electrical logs, core analysis (lithofacies, poro-perm, MICP), and customized workflow was used to characterize, classify, and map facies. Capillary pressure information and formation tester data were integrated and compiled for each facies. Moving forward, a new method was developed to model saturation height functions representing non-water wet formations and tilted WOC phenomena. Fluid and saturation properties are estimated and assigned to each reservoir point and after reservoir rock types (RRT) were defined. This method has been validated by applying the new approach to actual well data. The drainage capillary pressure (Pc) lab data in the reservoir intervals with established conventional WOC complemented interpretation results derived from acquired logs; however, for the reservoirs zones with identified tilted WOC, correlation and matching Pc lab data with logs was not possible. The new method provides saturation properties in formations with complex fluid-rock interactions and phenomena. This work introduces a novel approach to estimate saturation height functions and saturation distribution for reservoirs with complex fluid-rock interaction and distribution, such as non-water wet formations in tilted WOC conditions.