The productivity and economics of horizontal wells are governed by the ability of the transverse fractures to communicate efficiently with the wellbore, which is
strongly controlled by the conductivity of the proppant bed and the effectiveness of the fluid additives. These impact the relative permeability, the capillary pressure
and the effective conductivity in the proppant bed. When time at temperature, stress cycling, embedment, multiphase flow and non-Darcy effects are considered, the effective conductivity can be reduced 100-fold. Another investigated parameter is the impact of the wellbore location relative to the propagated fracture. If the
wellbore is high in the fracture, gravity segregation will cause liquid removal from the lower portion of the fracture to be very difficult. In low conductivity proppant
beds, capillary pressure will tend to retain high water saturations, thus lower conductivity even for the portions of the fracture above the wellbore.
Laboratory experiments have addressed these issues for proppants with a range of permeabilities from 10 to 100 Darcies; 100 mesh to 20/40 mesh and ceramics. The relative permeability to gas can be as low as 0.01, with as much as a 70-fold improvement when suitable proppants and additives are employed. Evaluation of the production performance of 240 wells, 98 with effective additives and 142 without, and covering a similar range of proppant types and sizes, shows a similar benefit to the wells' normalized 30 day recovery and gross value. These results clearly demonstrate that economic expediency can be detrimental to a well's ultimate value and hydrocarbon recovery.
The Austin Chalk formation has seen several active development booms over the past 35 years due to new technologies. Recently, a program was undertaken to test multistage fracturing technology in the Giddings Austin Chalk field to determine if sufficient additional reserves could be unlocked to spark another development boom. This paper highlights the challenges encountered during the project from the initial reservoir simulation and well candidate selection through system design and installation and treatment design.
The Austin Chalk formation has seen considerable horizontal development across Texas as operators chased areas of concentrated natural fractures. Significant quantities of hydrocarbons are apparently trapped in the tight carbonate matrix between the widely spaced fractures along the proven productive edge of the field. Many of the wells in these areas have poorly drained the Austin Chalk due to limited natural fracturing. Multistage fracturing has the potential to reach the insufficiently drained matrix blocks by isolating portions of formation between the natural fractures.
A total of 16 openhole multistage hydraulic fracturing completion systems have been run in the Giddings Austin Chalk field across four different counties in an effort to increase EUR's from existing wells and to extend the economic boundaries of the formation.
Simulation work done at the outset of the project pointed towards economic incremental recoveries from multistage hydraulic fracturing. This work also helped validate initial candidate selection. It was found that openhole multistage systems can be run into the Austin Chalk, but it was learned that due to high formation friction factors, careful design work was necessary to ensure that the completion equipment could be run to the desired depth. Results to date have shown that multistage fracturing can increase recovery from existing wells in poorly fractured areas as well as allow for economic development of previously uneconomic fringe areas.
Cherian, Bilu Verghis (Schlumberger) | Stacey, Edwin S. (Petro-Hunt LLC) | Lewis, Ray (Petro-Hunt LLC) | Iwere, Fabian Oritsebemigho (Schlumberger) | Heim, Robin Noel (Schlumberger) | Higgins, Shannon Marie (Schlumberger)
In field development programs where large variations in reservoir and completion parameters exist, the evaluation of reservoir performance to determine the optimal completion strategy can be a challenging task. This paper presents findings from a recent integrated cross-discipline analysis of a pilot program performed in the Bakken and Three Forks Formations (Williston Basin, North Dakota) to evaluate the impact of petrophysical and geomechanical properties on hydraulic fracture lengths, reservoir connectivity, well performance and well spacing.
Microseismic, geological, geomechanical, completions, engineering and production data were integrated in single and multi-well modeling approaches to provide an objective method to evaluate and compare well performance. Results and conclusions from various disciplines were validated by integrating operational observations with the modeling. The application of the proposed workflow allows one to (1) understand and evaluate the effect of fracturing parameters (length/conductivity) on well performance, (2) characterize reservoir and fracture properties using hydraulic fracture pressure and production history matching techniques (3) relate fracture parameters to reservoir, geology and mechanical properties and, (4) provide a methodology to understand key drivers controlling the development strategy of an asset.
The Bakken Formation is a widespread unit in the central and deeper portions of the Williston Basin in the states of Montana and North Dakota, in the United States, and the provinces of Saskatchewan and Manitoba in Canada (Figure 1). The formation is comprised of an Upper Shale Member, a Middle Siltstone Member and a Lower Shale Member (Figure 2). The Upper and Lower Bakken shales are organic rich and are the petroleum source rocks for both the Bakken and Three Forks Formations. Porosity in the middle member of the Bakken formation is in the range of 4% to 9%, and water saturation ranges between 25% and 50%, depending upon the county where wells are located. In the Williston Basin the Upper Bakken Shale is overlain by the Lodgepole Formation which consists of dense, dark gray to brownish gray limestone and gray calcareous shale. Below the Lower Bakken Shale is the Three Forks formation. The Three Forks is composed of thinly interbedded greenish gray and reddish brown shales, light brown to yellow gray dolostone, gray to brown siltstone, quartzose sandstone and minor occurrences of anhydrite (Kume, 1963). The contact between the Bakken and Three Forks appears conformable in the deeper portions of the basin and unconformable on the basin flanks. The Three Forks has an average of 30.5 ft pay thickness, 65% oil saturation and 6.9% porosity. The Nisku (or Birdbear Formation) is conformably overlain by the Three Forks Group.
A recently developed unconventional fracture model (UFM) is able to simulate complex fracture network propagation in a formation with pre-existing natural fractures. Multiple fracture branches can propagate simultaneously and intersect/cross each other. Each open fracture exerts additional stresses on the surrounding rock and adjacent fractures, which is often referred to as "stress shadow?? effect. The stress shadow can cause significant restriction of fracture width, leading to greater risk of proppant screenout. It can also alter the fracture propagation path and drastically affect fracture network patterns. It is hence critical to properly model the fracture interaction in a complex fracture model.
A method for computing the stress shadow in a complex hydraulic fracture network is presented. The method is based on an enhanced 2D Displacement Discontinuity Method with correction for finite fracture height. The computed stress field is compared to 3D numerical simulation in a few simple examples and shows the method provides a good approximation for the 3D fracture problem. This stress shadow calculation is incorporated in the UFM. The results for simple cases of two fractures shows the fractures can either attract or repel each other depending on their initial relative positions and compares favorably with an independent 2D non-planar hydraulic fracture model.
Additional examples of both planar and complex fractures propagating from multiple perforation clusters are presented, showing that fracture interaction controls the fracture dimension and propagation pattern. In a formation with small stress anisotropy, fracture interaction can lead to dramatic divergence of the fractures as they tend to repel each other. However, even when stress anisotropy is large and fracture turning due to fracture interaction is limited, stress shadowing still has a strong effect on fracture width, which affects the injection rate distribution into multiple perforation clusters, and hence overall fracture network geometry and proppant placement.
Valenzuela, Ariel (Pemex) | Guzman, Javier (Pemex) | Sanchez Moreno, Sabino (Pemex) | Garcia Mondragon, Gabriel (Pemex) | Gutierrez Rodruigues, Luis Alberto (Schlumberger) | Exler, Victor Ariel (Schlumberger) | Ramirez, Carlos (Schlumberger) | Parra, Pablo Alejandro (Schlumberger) | Pena, Alejandro Andres (Schlumberger)
The channel fracturing technique combines fracture modeling, materials and pumping methods to generate a network of highly conductive channels within the proppant pack. These channels aim at expediting the delivery of hydrocarbons from the reservoir to the wellbore (Gillard et al., 2010). This paper provides a comprehensive summary of the implementation of this novel technique in the Burgos basin, Mexico North.
The Eocene Yegua formation in the Palmito field near Reynosa, Mexico was selected for this study. This formation comprises sandstone layers with average permeability of 0.5 mD and Young's modulus in the order of 2.5 Mpsi. Key historical issues for the stimulation of this formation using conventional fracturing materials are limited polymer recovery and the consequential fracture conductivity impairment. Use of resin-coated proppants has also been implemented to prevent proppant flowback from these operations.
Gas production, treating pressure and polymer recovery data from a twelve-well campaign in the Palmito field (six wells treated via channel fracturing, six offset wells treated conventionally and aiming for similar fracture geometry) are summarized in the manuscript. Results indicate that the implementation of the channel fracturing technique improved fluid and polymer recovery, thus leading to increases in initial gas production by 32% and 6-month cumulative gas production by 19%. Such improvements in production were obtained with 50% less proppant per stage and smaller proppant particles. These observations are consistent with the hypothesis that the channel fracturing technique promotes the decoupling of fracture conductivity from proppant pack permeability. Positive features that were also observed during this campaign such as absence of proppant flowback issues without the use of resin-coated sand and non-occurrence of near-wellbore screen-outs are also reported and discussed.
The study concluded that the channel fracturing technique is a viable alternative to conventional fracturing methods for the stimulation of wells in the Burgos basin.
Hydraulic fracture completions seek to balance spacing of treatment wells and perforation clusters in order to minimize the costs of drilling wells and pumping fluids and proppant downhole while promoting the development of a discrete fracture network to connect even the most isolated pockets of hydrocarbon. To this end, numerous strategies for well completions have been proposed, such as avoiding the overlap of treatment volumes between adjacent wells and/or stages because of the risk that proppant and fluid will preferentially be diverted into earlier treated volumes. In counterpoint, it has also been suggested that the creation of new fractures in a previously treated volume promotes a complex fracture network enhancing drainage. When these stimulations are monitored from multiple arrays surrounding the treatment zone, seismic moment tensor inversion (SMTI) offers the ability to test these hypotheses by inferring if the events represent the opening of fractures or closure of pre-existing natural or newly created fractures. In this paper, we discuss two different completion programs. One common thread between the two data sets is that observed event clusters occur with a significant degree of overlap between neighbouring stages. Both completions were monitored with optimal multi-array configurations allowing for the calculation of SMTI with a high degree of robustness. The first stages in both examples showed significant opening components of failure. Neighbouring subsequent stages show closure events in the overlapping regions suggesting that the previously opened fractures were now closing due to local re-orientations of the stress-strain field stress induced by the later injection over-printing the region of overlap. Based on these analyses, it can be suggested that the moment tensor response can be used to identify the effective spacing for perforation clusters and establish optimal stimulation programs, which could include setting fracture ports farther apart.
Hydraulic fracturing is an essential technology for hydrocarbon extraction from both conventional and unconventional reservoirs. Recently, concern has developed regarding induced seismicity generated in association with multistage fracturing of horizontal wells in shale reservoirs. A review of thousands of fracture treatments that have been microseismically monitored shows that the induced seismicity associated with hydraulic fracturing is very small and not a problem under any normal circumstances. Results are presented for six major shale basins in North America.
Many shale gas reservoirs have been previously thought of as source rocks, but the industry now finds these source rocks still contain large volumes of natural gas and liquids that can be produced using horizontal drilling and hydraulic fracturing. However, one of the most uncertain aspects of shale gas development is our ability to accurately forecast gas resources and shale gas development economics. The uncertainty of the problem begs for a probabilistic solution.
The objective of our work was to develop the data sets, methodology and tools to determine values of original gas in place (OGIP), technically recoverable resources (TRR), recovery factor (RF) and economic viability in highly uncertain and risky shale gas reservoirs. Existing approaches for determining values of TRR, such as the use of decline curves or even volumetric analyses, may not be reliable during early time because there may not be enough production history for decline curves to work well or the uncertainty in the reservoir properties may be too large for volumetric analyses to be useful.
To achieve our research objective, we developed a computer program, Unconventional Gas Resource Assessment System (UGRAS). In the program, we integrated Monte Carlo technique with an analytical reservoir simulator to estimate the original volume in place, predict production performance and estimate the fraction of TRR that are economically recoverable resources (ERR) for a variety of economic situations. We applied UGRAS to dry gas wells in the Barnett Shale and the Eagle Ford shale to determine the probabilistic distribution of their resource potential and economic viability. Based on our assumptions, the Eagle Ford shale in the dry gas portion of the play has more technically recoverable resources than the Barnett shale. However, the Eagle Ford shale is currently not as profitable as the Barnett shale because of the higher drilling costs in the Eagle Ford dry gas window.
We anticipate that the tools and methodologies developed in this work will be applicable to any shale gas reservoirs that have sufficient data available. These tools should ultimately be able to allow determination of technically and economically recoverable resources from shale gas reservoirs globally.
This paper highlights the current state of fiber optic distributed acoustic sensing (DAS) technology by reviewing its application to hydraulic fracture diagnostics in a multi fractured horizontal well (MFHW). It will be shown that, with the advent of DAS, a gap in the feedback — which could previously occur using various hydraulic fracture diagnostic options — has now been filled. Results are shared that were obtained from the first documented successful application of high resolution DAS during the placement of multiple hydraulic fractures in a horizontal well that was recently completed with an open hole packer and frac valve system.
Observations were made of the real time soundfield in the near wellbore region during the fracturing process. High resolution images of the processed dataset have enabled the analysis of observations of key dynamic aspects of the process. In examining the resultant data, it has become apparent that DAS has overcome some limitations of those intrinsic in other diagnostic tools such as Distributed Temperature Sensing (DTS), microseismic monitoring, and tracer programs. An overview of the well design is provided as well as selected samples from the dataset which highlight some of the events that were observed during the hydraulic fracturing process. Samples of both real time images and processed high resolution soundfield data maps are presented. Processing work that is currently underway on the immense dataset is briefly discussed and two categories of field observations will be presented — firstly to examine the mechanical reliability aspects of the swell packer/ball actuated frac sleeve system, and secondly to examine details of the near wellbore such as single or multiple fracture initiation sites and the general behaviour of wellbore fluids over the course of the fracture treatment.
Distributed acoustic sensing using a single mode optic fiber has been described in recent literature (Molenaar, 2011) for applications involving the recording of acoustic events during various stages of well completion and stimulation. This paper provides further description on how DAS works and shares results from the successful application of a high resolution DAS survey, obtained while placing multiple hydraulic fractures in a horizontal well, completed in a tight sand using an open hole ball actuated valve system with swell packers for fracture isolation. Earlier findings are supported, in particular that DAS will enable an improved understanding of in-wellbore activities and, in so doing, that it will enable optimization of hydraulic fracturing design and execution. It is recognized that much is yet to be learned in the processing of fiber optic DAS data, but also that it would be beneficial to share the work that has been completed to date to facilitate accelerated development of DAS processing technology.
Gupta, Jugal (Exxon Mobil Corporation) | Zielonka, Matias (Exxon Mobil Corporation) | Albert, Richard Alan (ExxonMobil Upstream Research Co.) | El-Rabaa, Abdelwadood M. (Exxon Mobil Corporation) | Burnham, Heather Anne (XTO Energy) | Choi, Nancy Hyangsil (ExxonMobil Upstream Research Co.)
Fracture nucleation and propagation are controlled by in-situ stresses, fracture treatment design, presence of existing fractures (natural or induced), and geological history. In addition, production driven depletion and offset completions may alter stresses and hence fracture growth. For unconventional oil and gas assets the complexity resulting from the interplay of fracture characteristics, pressure depletion, and stress distribution on well performance remains one of the foremost hurdles in their optimal development, impacting infill well and refracturing programs.
To this end, ExxonMobil has undertaken a multi-disciplinary approach that integrates fracture characteristics, reservoir production, and evolution of the stress field to design and optimize developments of unconventional assets. In this approach, fracture modeling and advanced rate transient techniques are employed to constrain fracture geometry and depletion characteristics of existing wells. This knowledge is used in finite element geomechanical modeling (coupling stresses and fluid flow) to predict fracture orientation in nearby wells.
In this paper, an integrated methodology is described using case studies for two shale gas pads. The study reveals a strong connection between reservoir depletion behavior and the spatial and temporal distribution of stresses. These models predict that principal stresses are influenced far beyond the drainage area of a horizontal well and hence play a critical role in fracture orientation and performance of neighboring wells. Strategies for manipulating stresses were evaluated to control fracture propagation by injecting, shutting-in, and producing offset wells. Collective interpretation of completion, reservoir depletion and changes in stresses explained varying performances of wells and enabled evaluation of infill potential on the pad. This workflow can be used to develop strategies for (1) optimal infill design, (2) controlling propagation of fractures in new neighboring wells, and (3) refracturing of existing wells.