Using large-scale hydraulic-fracturing experiments on tight shale outcrops, three dominant regions controlling stage production were identified—the connector between the wellbore and the fracture system, the near-wellbore fracture, and the far-wellbore fracture network. The particular nature of these regions may change depending on the play, the reservoir makeup, its relation to the in-situ stress, and the distribution of rock properties; however, these regions are always well differentiated. Understanding the role of each of these components in hydrocarbon production is fundamental to identifying the dominant sources of fracture-conductivity loss and accelerated production decline.
Introduction
Achieving economic production from nanodarcy-scale-permeability, organic-rich-mudstone reservoirs requires creating large surface area by hydraulic fracturing. More importantly, economic production depends on preserving the created surface area and fracture conductivity during long-term production. This paper is about understanding the surface area (fracture geometry) that is created in heterogeneous rocks with complex makeup, preserving the surface area after fracturing, and maintaining adequate fracture conductivity during long-term production.
Fig. 1 shows a conceptual representation of the interaction of the propagating fracture with weak interfaces and weak bedding as a function of distance from the wellbore. Branching and step-overs (not shown) also develop vertically, providing resistance to flow and to upward fracture growth. Three regions of fracturing with unique properties emerge from this concept: the wellbore/fracture connector, the near-wellbore fracture, and the far-wellbore fracture. The wellbore connector (possibly 10–30 ft) is the region of highest hydraulic convergence and appears to be a choking point for production. This is particularly so if it is not propped appropriately. The near-wellbore fracture is of limited extent (200–400 ft) and represents most of the propped surface area and possibly most of the produced hydrocarbons. Unfortunately, proppant transport in the far-wellbore fracture region is minimal; the created far-field surface area is easily lost and does not contribute to production. This loss of surface area at the far-wellbore region may not be avoidable by operational changes at the wellbore.
Laboratory Testing and Results
Large-block samples provide the best opportunity for evaluating hydraulic-fracturing propagation and the interaction of fractures with planes of weakness in the rock. For laboratory testing, the authors used a polyaxial stress frame with independent stress control along three perpendicular directions and a maximum capacity of 8,000 psi.
Flatjacks are used for transmitting the load and for continuously monitoring block deformation during fracturing. These measurements permit detection of fracture initiation and fracture breakdown and monitoring whether the fracture is predominantly planar or nonplanar. The blocks are also instrumented with an array of acoustic transducers (typically 20 to 36 and occasionally 76). These transducers are used to conduct active transmission measurements, which provide a continually updated velocity model of the block (every 2 seconds). This helps account for changes in acoustic velocity resulting from loading and fracturing. The transducers were used concurrently in passive mode to detect and localize acoustic emission events, and these were used to map the evolution of the fracture geometry.
Fracture Regions Controlling Stage Production
Fig. 2 shows the four regions of the fracture system. The wellbore region (with casing and cement) was cored to reveal the fracture geometry in this region. The location of the slotted sections is shown with a blue rectangle. The wellbore/fracture connector is the region immediately outside the slotted region. In this test, the connector exhibits a simple and planar geometry and has lower proppant concentration (which was partially washed out during wellbore coring). The near-wellbore fracture region follows the wellbore/fracture connector region and is characterized primarily by the presence of high proppant concentration and a surface area with moderate fracture complexity. The far-wellbore fracture region follows the near-wellbore fracture region and is characterized by the increased fracture complexity, increased surface area, and substantially decreased proppant concentration. The authors believe that understanding the role of each of these regions in controlling hydrocarbon production is fundamental to understanding long-term production and improving the design of hydraulic fracturing.
Wellbore. The wellbore geometry, its orientation, and the type of completion (e.g., cased, openhole, perforated, sand blasted) define the stress concentrations that affect fracture initiation and breakdown and affect the geometry of the wellbore/fracture connector region connecting the wellbore to the created surface area. For example, the presence of weak interfaces along the wellbore may facilitate fracture breakdown and improve the connectivity to the near-wellbore fracture system. However, this will depend on the wellbore orientation in relation to these planes of weakness and the orientation of the stress. Critical concerns for landing and for selecting the wellbore azimuth are mechanical stability, creep, in-situ stress magnitude, orientation, rock elastic anisotropy, pore pressure, and adequate rock competence for maintaining connectivity with the wellbore/fracture connector over time.
Wellbore/Fracture Connector Region. The wellbore/fracture connector region (the connector) defines the connection between the wellbore and the near-wellbore fracture system. This is a region of limited extent (possibly 10–30 ft in the field) but of great importance to well production. This is where the wellbore stress concentrations, the regional in-situ stress, the perforations (or any other geometry used for fracture initiation), the choice of fluid properties, fluid rates, the pumping schedule, and other design properties strongly influence fracture initiation and development. The desirable result is to create a connector with maximum fracture conductivity between the wellbore and the near-wellbore fracture system, minimizing any potential restrictions of flow and remaining open during long-term production. This means obtaining a wide conduit with single and simple planar geometry, maximum fracture width, high fracture conductivity, minimal fracture tortuosity, limited changes in direction during propagation, and limited generation of fracture branches with reduced widths.
The connector, a region of high fluid velocity, may also be a region of limited proppant deposition. This may be particularly true for single and simple fractures where the flow rate is at the maximum and the proppant precipitation may be low during the duration of the treatment. If so, this will promote early closure of the connector and significant restriction to hydrocarbon production. Rock properties with low surface hardness, high clay content, low modulus, high creep, and high rock/fluid interaction are problematic for developing a long-lasting connector with sustained fracture conductivity. On the basis of a large number of laboratory experiments and analysis of field data during fracture breakdown, the large variability in stage production and the current inefficiency of the stimulation process appear to be controlled primarily by the closure of the connector. This may be the weakest link of the hydraulic-fracturing pathway.
Near-Wellbore Fracture Region. The near-wellbore fracture region is the dominant region of hydrocarbon production. It is also the region with the highest proppant concentration and has limited surface area. The near-wellbore fracture region is primarily susceptible to solids trapping and salt precipitation during long-term production. It is also susceptible to solids production by high drawdown, proppant embedment, rock extrusion by proppant embedment, mobilization of fines, and loss of fracture conductivity resulting from all these factors. It is susceptible to imbibition and loss of fracture-face permeability. Imbibition produces a water block at the fracture face that moves away into the far-field reservoir. This strongly reduces the fracture-face permeability immediately after fracturing. Rock/proppant embedment results in local plastic deformation that may lead to dramatic reduction in fracture-face permeability at the rock/proppant interface.
The part of the near-wellbore fracture region that is closer to the wellbore is a potential filter for retention and trapping of fines, fragments, precipitants, and all other plugging constituents that are mobilized from the farther regions of the fracture. Thus, the gradual loss of fracture conductivity in this region is possibly inevitable, and this effect may be the major source of fracture-conductivity reduction over a short period of time, corresponding to a loss in productivity. Pillar proppant placement will facilitate movement of the fines and prevent rapid loss of fracture conductivity in this region.
Far-Wellbore Fracture Region. Fracture containment is a dominant concern in the near-wellbore and the far-wellbore fracture regions, and this is perhaps more important for the latter. Transporting proppant to the far-wellbore fracture region and attaining sufficient proppant concentration to keep fractures in this region open are of highest concern. Loss of surface area is possibly the dominant problem in this area. At low proppant concentrations, low fracture widths, and high proppant/rock stress concentrations, rock/proppant interactions are critical to define whether proppant embedment or proppant crushing controls the potential for fracture closure. In addition, rock/fluid interactions soften the rock and promote embedment; proppant/fluid interaction weakens sand when it is used as proppant and promotes proppant crushing. In either case, the potential for loss of surface area is high.
The far-wellbore fracture region, the region with the highest surface area, is also a region of salt dissolution and high salt concentration in the fracturing fluid, leading to potential precipitation in the proppant pack at the near-wellbore fracture region during flowback. It is also a region of high water imbibition, which results in water blocking and fracture-face-permeability impairment. Fundamentally, however, it is a region with minimal proppant concentration and high loss of surface area immediately after fracturing.
Summary and Recommendations
- Productivity from the connector region depends on long-term mechanical stability and is independent of reservoir quality. The goal is to create a simple, single, wide fracture connector with adequate proppant support to prevent fracture closure and proppant plugging over time. This requires competent rock with high surface hardness, low time dependence (low creep), and low softening associated with rock/fluid interactions.
- Productivity from the near-wellbore fracture region depends on the propped area of contact with high-reservoir-quality rock and the long-term retention of fracture conductivity and fracture-face permeability. This requires height-growth containment to maximize surface area in contact with the reservoir, fracture-width control (flow rate, viscosity, and fracture pressure) to extend the region of moderate fracture complexity, nonhomogeneous proppant distribution to minimize retention of solids from the far field, and limited loss of fracture-face permeability.
- Productivity from the far-wellbore fracture region depends on proppant placement and retention of fracture conductivity during flowback and early production.
- The wellbore is not a region of fracturing, but its placement and completion configuration play a strong role in the development of the other regions. In particular, it has a controlling effect on the evolution and geometry of the connector region.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166505, “Defining Three Regions of Hydraulic-Fracture Connectivity in Unconventional Reservoirs Helps in Designing Completions With Improved Long-Term Productivity,” by Roberto Suarez-Rivera, SPE, Schlumberger; Larry Behrmann, Schlumberger consultant; Sid Green, SPE, Schlumberger and University of Utah; and Jeff Burghardt, SPE, Sergey Stanchits, Eric Edelman, SPE, and Aniket Surdi, Schlumberger, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September–2 October. The paper has not been peer reviewed.