Jones, Drew (Deep Imaging) | Pieprzica, Chester (Apache Corporation) | Vasquez, Oscar (Deep Imaging) | Oberle, Justin (Deep Imaging) | Morton, Peter (Deep Imaging) | Trevino, Santiago (Deep Imaging) | Hickey, Mark (Deep Imaging)
We used a new, large-scale, surface-based, controlled-source electromagnetics (CSEM) approach to map the locations of frac fluid during flowback following a three-well hydraulic fracture stimulation in the Permian Basin. CSEM records and analyzes electric field signals induced in the electrically conductive frac fluids by a surface-based transmitter. For this study, we placed a grounded dipole transmitter directly above the central horizontal well of three parallel neighboring wells. The transmitted signal was a broadband pseudo-random binary sequence. To record the frac fluid response signal, we placed an array of 161 receivers on the surface covering the three horizontal wells. We recorded the induced, response signals of the flowback fluids in three-hour intervals (three on, three off) for 228 hours. The CSEM recording started eleven days after flowback began on the central well and four days after flowback began in the two outer wells. From this time-lapse recording we captured the spatial and temporal change in electrical conductivity within the fractured reservoir, allowing us to infer the location of flowback fluid and its movement. During the stimulations chemical tracers had been included in the frac fluid. Analysis of the tracers captured during flowback agreed well with the mapped fluid locations and movement found in the CSEM data.
Flowback monitoring and its interpretation offer another valuable tool for frac and reservoir engineers. This understanding is especially critical in developing and managing unconventional reservoirs. Here, the stimulation responses are not simple, more and more evidence show complex fracturing and complex fracture networks (e.g., Rassenfoss, 2018). Characterizing a fracture network or networks in shale (i.e., an unconventional reservoir) is a challenging task. It is complicated by multiphase and complex flow regimes, non-static permeability and porosity, natural fracture and flow systems, heterogeneities and complex stress, changing stress with production, liquid loading, and a host of operational concerns (Zolfaghari et al., 2016). In the past, to determine hydraulic fracture properties, operators used production data in a variety of models to manage wells and reservoirs. Garnering production data can take months or even years delaying, for example, upgrades to well and stimulation designs and designing infill drilling (Williams-Kovacs, Clarkson, & Zanganeh, 2015). In contrast, a flowback occurs during the transition between stimulation and bringing the well online. Understanding the flowback provides significant improvements in determining early production rates enabling estimates of the effective size of stimulations, distinguishing key reservoir properties, and predicting long-term production rates (Jacobs, 2016). In addition, there can be direct savings if, for example, flowback interpretation identifies an underproducing play in time to redirect funds into a more lucrative play before infill drilling (Williams-Kovacs et al., 2015).
The expansion of unconventional resources development has placed emphasis on better understanding of hydraulic fracturing stimulation effectiveness and the area of pay affected by the fracture treatment to optimize well spacing and improve completion and stimulation effectiveness. Existing fracture diagnostic methods such as microseismic monitoring and tiltmeters do not provide information about fracture connectivity to the wellbore. In this paper, we present a chemical tracer flowback based fracture diagnostic and analysis methods to estimate the fractional contribution of each created fracture stage, which is open and connected to the wellbore to help improve field development strategies and provide valuable information on optimal well paths for future drilling and development. The findings out from the stage production contribution profiles using the chemical tracer technology allows engineers to improve stimulation efficiency in multistage hydraulic fracturing horizontal wells applications for completion optimization and production enhancement. Two case histories are presented in which the chemical tracer technology was applied to two horizontal wells. The results of the chemical tracer analysis were correlated to production data, reservoir parameter and other diagnostic tests. The resultant findings from the analysis help evaluate completion and stimulation effectiveness and determine the extent of inter-well connectivity of the fracture network and then used to optimize future completions in the region.
Ibrahim Mohamed, Mohamed (Colorado School of Mines) | Salah, Mohamed (Khalda Petroleum) | Coskuner, Yakup (Colorado School of Mines) | Ibrahim, Mazher (Apache Corp.) | Pieprzica, Chester (Apache Corp.) | Ozkan, Erdal (Colorado School of Mines)
A fracability model integrating the rock elastic properties, fracture toughness and confining pressure is presented in this paper. Tensile and compressive strength tests are conducted to define the rock-strength. Geomechanical rock properties derived from analysis of full-wave sonic logs and core samples are combined to develop models to verify the brittleness and fracability indices. An improved understanding of the brittleness and fracability indices and reservoir mechanical properties is offered and valuable insight into the optimization of completion and hydraulic fracturing design is provided. The process of screening hydraulic fracturing candidates, selecting desirable hydraulic fracturing intervals, and identifying sweet spots within each prospect reservoir are demonstrated.
Mohamed, Mohamed Ibrahim (Colorado School of Mines) | Salah, Mohamed (Khalda Petroleum) | Coskuner, Yakup (Colorado School of Mines) | Ibrahim, Mazher (Apache Corporation) | Pieprzica, Chester (Apache Corporation) | Ozkan, Erdal (Colorado School of Mines)
Diagnostic fracture injection test (DFIT) has become a valuable tool to quantify reservoir properties and hydraulic fracture characteristics. The pressure decline response of DFIT test reflects the process of fracture closure and the flow capacity of the reservoir. Previous literature provided simplifying assumptions to analysis the DFIT. However, operating companies often face challenges in the DFIT data interpretation due to several complex factors that result in non-ideal DFIT behavior and inconsistent results that lead to significant incorrect estimation of reservoir properties and fracturing parameters, including interaction with natural fractures, heterogeneous rock properties, variable storage, etc. The objective of this paper is to investigate the non-ideal DFIT behavior and factors that affect DFIT data and interpretations. The paper explained the flow regimes observed before closure and after closure during DFIT under complex reservoir conditions of natural fracture activation and fracture tip extension for reliable estimation of reservoir properties and fracture characteristic from actual field DFIT data. The overall falloff period is analyzed using pressure transient analysis diagnostic plots and leak-off modeling. The transient pressure during the falloff period is highly affected by the residual leak-off and continuing after flow that could disturb formation flow regimes during the test, affecting the ability to get correct pore pressure or formation permeability. The paper explains the various mechanisms affecting the pressure transient behavior during DFIT and adapts the wellbore and leak-off process to be able to observe reservoir response and get more realistic fracture characteristics and reservoir properties.
Ibrahim Mohamed, Mohamed (Colorado School of Mines) | Coskuner, Yakup (Colorado School of Mines) | Salah Mohamed, Mohamed (Khalda Petroleum) | Ibrahim, Mazher (Apache Corporation) | Mahmoud, Omar (Apache Corporation) | Pieprzica, Chester (Apache Corporation)
Unconventional reservoirs have been defined as formations that cannot be produced at economic flow rates or that do not produce economic volumes of oil and gas without horizontal well with hydraulic fracture treatments. Horizontal well fracturing efficiency in unconventional reservoirs is the main factor for the success of developing unconventional reservoirs. The early focus of the industry was on the operational efficiency and during this period, the geometric spacing of perforation clusters adopted as the preferred completion method. Cipolla et al. (2011) presented a case study on the interpretation of production logs from hundreds of horizontal wells. The results indicated that 60% of perforation clusters contribute to production when completed geometrically and completion cost could reach more than 60% of the total well cost. Recently, numerous studies have been undertaken to understand this phenomenon. Increasing the stimulation effectiveness and maximizing the number of perforation clusters contributing to productivity was an obvious area for improvement to engineer the completion design. The uniform initiation and distribution of fractures in each frac stage is very complex because there are many factors affecting the fracture initiation such as stress orientation, heterogeneity, existing of natural fractures, and completion design. This paper presents sensitivity studies investigating the effect of the formation permeability, fracture spacing, fracture half-length, fracture conductivity, flowing bottom hole pressure, and outer reservoir permeability on the well ultimate recovery efficiency by using analytical simulator.
The application of those methods is depending on the behavior of each relation. This work presents a new look at decline curve methods for reserves estimation in unconventional gas reservoirs. Recommendations are also presented based on practical applications, which might help in understanding the behavior of such problematic calculations. Additionally, a recommended workflow is presented for better application of decline curves in estimating unconventional reserves using a short period of production. Introduction Exploration and development of unconventional resources have grown dramatically over the last decades in different countries, especially in North America. It is often may called the revolution of North American energy production. The technological advancements and using effective techniques, such as multi-fractured horizontal wells, are the main key elements for the huge exploitation of such resources (Yu et al. 2013; Chen et al. 2015; Figueiredo et al. 2017).
Forecasting future production and estimating ultimate recovery (EUR) in supertight reservoirs and shale plays has long been problematic. Developing a reliable and more accurate production forecast have always been a main goal of any petroleum operation. Effectively assessing the reservoir volume and well producing life is instrumental for creation of development scenarios and strategies to maximize the value to the company. Different models have been introduced and used for reserves estimation and production forecast of unconventional reservoirs. This work is intended to review and compare the methods and models currently used in the industry.
Reserves estimation is a process that is constantly updated during the life of a reservoir. Its accuracy depends on the amount of data available and the method of forecast. Analytical models or rate transient analysis (RTA) methods are widely used for history matching and production forecast of unconventional reservoirs. Numerical simulation is also used for estimating ultimate recovery. Different relations have been introduced to model the rate/time behavior in unconventional plays as an alternative to the Arps’ decline curve analysis to address shortcomings when matching production history. Modified hyperbolic decline, power-law exponential decline (PLED), stretched-exponential decline (SEPD), Duong's method, and logistic-growth model (LGM) are developed for forecasting the production in shale reservoirs, but all are based on empirical observations of a particular scenario.
In this study, different methods of history matching the production of hydraulically fractured unconventional reservoirs were investigated by forecasting future production and predicting EUR's to quantify the differences between them. The traditional Arps’ decline for low permeability reservoirs over-forecasts reserves. PLED, SEPD, LGM, and Duong's method were intended to represent the character of rate/time production data for the standard well completion in a multiple-fractured horizontal well in a shale play. These methods provide different forecasts as they have different equation forms. Unfortunately, all of them are not satisfactorily sufficient to forecast production for all unconventional reservoirs. The RTA analytical models required certain modifications of the reservoir and fracture parameters to provide optimistic EUR when compared to the numerical simulation.
Different methods for forecasting unconventional well data have been reviewed and compared in this work based on the production forecast and EUR prediction. Field case production data has been used to reveal the accuracy of the models, the similarity of reserves estimation, and the relationship to the reservoir theory.