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.
Alekseenko, Olga Petrovna (Schlumberger Technology Corp.) | Potapenko, Dmitry Ivanovich (Schlumberger) | Cherny, Sergey G. (Institute of Computational Technologies, Siberian Branch of Russian Academy of Sciences) | Esipov, Denis (Institute of Computational Technologies, Siberian Branch of Russian Academy of Science) | Kuranakov, Dmitry (Institute of Computational Technologies, Siberian Branch of Russian Academy of Science) | Lapin, Vasily (Institute of Computational Technologies, Siberian Branch of Russian Academy of Sciences)
A 3D numerical model of fracture initiation from a perforated wellbore in linear elastic rock is developed, which allows one to determine the fracture initiation pressure (FIP) and the location and direction of an initial rupture. The model assumes that the fracture initiates at the point where the local maximum tensile stress exceeds the rock tensile strength. The 3D boundary element method is used for stress analysis.
The model is aiming at predicting the location of initial fractures and the difference in FIP between different perforation intervals in arbitrarily oriented non-cemented wellbores. There are many practical applications where this knowledge is required, but of particular interest for this research is the employment of differently oriented perforations for creating heterogeneity of FIP between wellbore intervals in multistage fracturing treatment. This can enable stimulation of these intervals in a sequential mode and significantly simplify current treatment diversion and completion practices.
Comprehensive analysis revealed that the main parameter that can be used for controlling FIP during multistage fracturing treatment is the angle between the direction of the perforation channel and the preferred fracture plane. The model allows obtaining the range of the angles that is the most suitable for designing and implementation of diversion between the perforated wellbore intervals. The influence of geometrical parameters of perforation (e.g. length, diameter and shape) on FIP is substantially less. Addtionally we found that against all expectations increase of perforation diameter can result in higher FIP. It was also discovered that the influence of the intermediate in-situ stress on FIP is comparable with the effect of perforation misalignment especially in the situation of horizontal wellbore and properly aligned perforations. Based on the model developed, an approximate approach to the evaluation of the impact of wellbore cementation on fracture initiation was suggested. It was discovered that taking into account the state of stress within the cement prior to well pressurization can result in both an increase
and reduction of FIP depending on the parameters of perforating as well as wellbore orientation.
The presented model is the necessary step toward predictable and controllable fracture initiation, which is vital for multistage fracturing treatment diversion.
The inclusion of fracture networks in reservoir models is generally based on the concept of failure associated with subvertical fractures. In general, it is surmized that fractures can grow irregularly in a stress field that is perturbed by a hydraulic fracture injection. It has also been considered that structural weaknesses in the rock such as pre-existing fractures and naturally occurring laminations commonly found in shale-gas reservoirs can be conduits for fracturing during stimulation and active pathways for fluid flow. We postulate that local stress perturbations through stress transfer allows for fractures to propagate and initiate failure along pre-existing fracture sets, which include sub-vertical and sub-horizontal fractures. Additionally, the degree of fracture interconnectivity and the type of fracturing will play a role in whether effective proppant transport is achieved. Through moment tensor inversion of microseismic events related to stimulation in the Horn River Basin utilizing well-conditioned geophone arrays, we have been able to define a three dimensional discrete fracture network consisting of sub-horizontal and sub-vertical fractures. Geologic data from the site provided corroborative evidence to the validity of the observed discrete fracture network, the presence of sub-horizontal fractures and fracture orientations in-line with current regional stress field. The fracture intensity and complexity appeared to be directly related to the degree of interaction between the sub-horizontal and sub-vertical fractures. Regions dominated by sub-horizontal fractures were also regions exhibiting poor fracture intensity and complexity. Based on these observations and moment tensor derived failure modes (opening component of failure), we were able to identify regions of enhanced fluid flow, further identifying regions of effective fluid transport. Regions with poor connectivity and dominance of sub-horizontal fractures also were identified as regions of poor fluid flow; these then become regions for potential re-stimulation. Based on these analyses, it can be suggested that sub-horizontal fractures can play an important role in the overall fracture development.
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.
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.
In this study, the authors have analyzed well and production data beginning with more than 400 wells in the greater Sanish-Parshall area of the Bakken. The study used Geographical Information System pattern-recognition techniques along with other data-mining techniques to interpret trends in the data sets. The study was made possible by combining data sets from the North Dakota Industrial Commission Oil and Gas Division, public data, and in-house proprietary data.
The study was designed to search for relevant trends in the distribution of production results for wells completed with fracturing sleeves and packers, plug and perforated, or complex completions to determine whether differences in productivity existed and needed to be factored into completion recommendations.
Trends examined in the project in addition to completion type included treatment parameters such as fracturing fluid types and quantities, proppant types and quantities, number of completion stages and stage lengths, perforation cluster spacing and length, and calculated perforation friction drop. All parameters analyzed were examined for statistical importance.
This work is significant in that it shows that the application of practical data-mining methods to an intermediate-size Shale Oil (light, tight oil) well data set can result in learning key lessons that may not be apparent when working with small data sets. This work is significant in the use of merged reservoir quality proxies, well architecture data, completion data, and stimulation data, against which production results are placed in geographical perspective of the Bakken Formation for improved interpretation. The work is also significant in that it may be used to allow selection of completion systems on the basis of completion time and cost balanced against concerns over differences in well production impact of one system over another, e.g., frac sleeves versus plug and perf type and complex
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.
Proppants are essential to the success of most hydraulic fractures and often account for the overwhelming cost of the treatment. Both the mass of proppant and the selection of the right type of proppant are essential elements in gaining the highest Net Present Value (NPV).
It has been generally believed that in the lower closure stress environment (below 6,000 psi, i.e., shallow reservoirs), natural sands such as Brady and Ottawa are appropriate as proppants and, for the same mesh size, they provide essentially the same permeability. Commonly accepted notion is that manmade proppants (such as ceramics) should be applied at higher closure stress environment, invariably, deeper reservoirs.
Three types of proppants are studied for a gas reservoir of Eagle Ford basin: Brady sand, Ottawa sand and ceramic. A fracture optimization p-3D model is used to maximize well performance by optimizing fracture geometry, including fracture half length, width and height. Reduced proppant pack permeability is compensated by larger width. Non-Darcy effects in the fracture are also considered. Post-treatment well performance is then estimated, using the optimized well geometry, leading to cumulative production over the well life. Finally, NPV analysis is employed as the criterion to select the best proppant for the job.
In this project, we show there is an optimum Proppant Number corresponding to maximum NPV in various reservoir permeability. Based on that, we propose a systematic way of choosing proppant type and mass to maximize NPV in oil reservoirs. For tight gas reservoirs, we correct the prejudice that natural sand proppants cannot be applied to deeper reservoirs by showing NPV study results that are superior to those of manmade proppants. Keeping stimulation costs down, natural sands proppants have a much larger range of applicability than previously thought.
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.