Unconventional/complex reservoirs

Focus on Unconventional Reservoirs Requires Advancements in Technology

Recent industry activities have turned their focus to the areas of liquid-rich shale (LRS) and light tight oil (LTO) along with unconventional tight and shale gas.

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In the current high-oil-/low-gas-price North American environment, and considering the new options available for well-completions technology in unconventional reservoirs, recent industry activities have turned their focus to the areas of liquid-rich shale (LRS) and light tight oil (LTO) along with unconventional tight and shale gas. Integrated workflows are important to the successful execution of this portfolio, and cutting-edge integrated technologies must be viewed as key enablers.

Introduction

Commercially and economically viable shale plays require the presence of some key conditions, which fall into two groups: reservoir quality/productivity and fracability (i.e., the ability to place effective and conductive stimulations). Factors that affect reservoir quality and productivity are the matrix porosity and permeability, organic carbon content, maturity and kerogen type, and fluid composition and pressure/volume/temperature properties. Two key factors that affect fracability are mineralogy and local in-situ-stress magnitude, orientation, and distribution.

To develop unconventional gas (UG), LTO, and LRS plays more effectively, significant advancements in understanding geological, geophysical, geochemical, geomechanical, petrophysical, reservoir, and stimulation properties have been made in the last decade. However, we are still just scratching the surface, and rapid integration across disciplines is required for success. In addition, continuous learning from exploration through to the end of field life must occur.

Geophysical Practices and Technologies

Geophysical technologies have always played a crucial role in the exploration and development of unconventional resources. They are used to define subsurface properties and to detect and monitor microseismic activities in the subsurface during completion and production. The recent, rapid increase in unconventional appraisal activity and the large diversity of geological settings require continuous innovation in geophysical-data collection, processing, and interpretation. Engineering activities, such as well and completion design, hydraulic-fracture monitoring, and production analysis and forecasting, are the major drivers for geophysical technologies. The three most common geophysical technologies are surface seismic, nonseismic methods (mainly potential-field methods), and microseismic or other downhole acoustic techniques (Fig. 1).

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Fig. 1—Main geophysical technologies in exploration and development of UG, LTO, and LRS plays.

 

For exploration and appraisal, a large number of 2D-seismic lines, with limited 3D-seismic surveys, are required data sets. In the development stage, 3D-­seismic data are crucial for reservoir characterization and well placement (as well as engineering-related applications). Advanced interpretations have become an essential part of understanding play complexity, optimizing well placement, and mitigating drilling geohazards. Seismic data also play an important role in providing geological boundaries for building geological frameworks and geomechanical models.

Seismic inversion is another workhorse in the subsurface evaluation of unconventional plays. It provides invaluable quantitative reservoir information for well- and areal-based delineation of sweet spots. Seismic-derived geomechanical rock properties are recognized as invaluable in understanding and analyzing completion and production results. This type of data set may also be used for production prediction. Post-stack and prestack seismic attributes are particularly useful in mapping and characterizing natural-fracture systems. The most commonly used seismic attributes include curvatures, semblance, ant track, and fracture intensity and orientation.

Nonseismic methods are mainly referred to as potential field methods, which include gravity, magnetic, and electromagnetic. There is a new role for these traditional technologies to play in derisking unconventional resource plays because, in comparison with seismic data, potential field data are less expensive to collect and often cover an area significantly larger than that covered by seismic surveys.

Microseismic has become a routinely used technology for monitoring stimulations and analyzing completion efficiency in unconventional plays across the globe. This technology enhances our understanding of hydraulic stimulation and provides information for optimizing stimulation design.

Geomechanics, Fracability, and Effective-Stress Estimation

Rock geomechanical properties play a key role in unconventional-reservoir appraisal and development because they influence the dimension and configuration of the stimulated rock volume (SRV), as well as wellbore stability during drilling operations. Geomechanical characterization consists of determining the in-situ stress regime, stress magnitude, rock mechanical properties, and pore pressure.

Even in reservoirs that have laminations, which can be vertically connected using hydraulic-fracture stimulation, it is often difficult to place a durable, conductive fracture that will maintain hydraulic conductivity and continuity over time. Therefore, the landing depth of the horizontal lateral within the pay section is critical.

Because most shale reservoirs are laminated, it is critical to design and execute hydraulic-fracture jobs that maximize effective vertical fracture growth. However, if overburden is the minimum principal stress (even in only a few laminations), the vertical coverage may be limited because hydraulic fractures would tend to grow horizontally.

Fracability is another key parameter that dictates how hydraulic fractures initiate, extend, and develop to establish an effective and conductive SRV. Fracability is a function of both static properties and dynamic reservoir behavior throughout the exploration and development phases. It is a function of the reservoir structure, reservoir properties, and in-situ conditions.

Estimating dynamic properties, through limited static data, early in play development is difficult at best and is not even possible in most cases. An alternative approach is to quantify/estimate selected key parameters from static data and provide a range of dynamic behaviors that is based on these parameters, which include

  • Stress anisotropy
  • Brittleness
  • Pressure-dependent leakoff
  • Rock-mechanical-property contrast
  • Material- (shear-) failure potential
  • Fracture and matrix compliance

Effective-Stress Estimation and Mapping

The estimation of effective stress (i.e., total stress minus pore pressure) is crucial to the success of many unconventional plays. Pressure prediction, the most common parameter in geomechanical modeling, is more complex in unconventional plays because measurements during drilling are not reliable because of the very-low- or no-flow conditions often encountered. Two field-proven test methods generally used to estimate unconventional pore pressure are diagnostic fracture injection tests (DFITs) and shut-in pressure-buildup tests.

Through extensive data collection and careful reinterpretation of a number of DFITs, important relationships between effective stress and productivity have been discovered for reservoir layers in unconventional plays. It is clear that production is limited for wells that have high effective stress and that production improves substantially as the effective stress decreases. Thus, early screening and sweet-spotting efforts will benefit from including an analysis of effective stress.

To this end, a modeling scheme was developed that first calculates strain resulting from 3D faulting and extension/compression of individual geological layers under different tectonic conditions and then combines these to locally estimate total deformation. The primary goal of this modeling scheme is to identify areas of low net stress, which will likely be more productive and more optimal for hydraulic fracture initiation and propagation and for the ultimate production. An example is presented in Fig. 2, which shows the effective-stress map for a particular reservoir layer in an unconventional play. Lighter colors show potential areas where effective stress is low, and warmer colors highlight the areas having higher net stress and, therefore, low estimated production rates.

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Fig. 2—Example of an effective-stress map.

Unconventional Well Completions and Stimulation

Unconventional wells require stimulations that are orders of magnitude larger than those for conventional wells. This is often achieved by drilling horizontal wells and pumping many hydraulic fractures along the lateral length. In UG, LRS, and LTO development, horizontal wells with laterals of 3,000 ft or more and 30–100 individual fractures are not uncommon. Even with this high stimulation intensity, typical recoveries per well range from 2 to 10% of the resource in place. Therefore, many closely spaced wells, often directionally drilled from pads, are required to reach the desired recovery. Fig. 3 shows an example of a typical pad layout in an unconventional asset.

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Fig. 3—Pad layout for an unconventional reservoir—five horizontal wells with multiple fractures.

 

Completions and stimulations of unconventional wells typically account for 40–60% of the total well cost, so optimizing these operations is critical.

Completion and Fracture Diagnostics. Fracture diagnostics refers to techniques that provide direct and indirect measurements of the parameters that influence fracture geometry and performance. Examples of diagnostics include

  • Microseismic—to estimate fracture geometry and orientation
  • DFITs—to measure minimum stress, pore pressure, and reservoir transmissibility
  • Production-logging tools—to measure production from each fracture stage
  • Liquid-soluble, solid, and other tracers—different types are used to measure, for example, fracture-height growth or to estimate which fractures are contributing in a multifracture environment
  • Optical fiber—to measure wellbore temperatures and noise over time
  • Pressure-monitoring wells—dedicated wells to measure pressure depletion over time and that can be used to history match the fracture geometry and reservoir permeability

Optimizing Diversion of Hydraulic Fractures

Diversion of hydraulic fractures along a horizontal or vertical well to maximize stimulation effectiveness is important for field-development success; how­ever, this is an economic balancing act. In the one extreme case, each fracture could be pumped individually, resulting in an extremely high well-completion cost but the highest possible stimulation efficiency. The other extreme case is to stimulate all zones at the same time with no concern for diversion of the fluid; this notionally results in the lowest possible well-completion cost but also the least effective stimulation. The best economic solution lies somewhere in the middle; to this end, different techniques for diverting fluid have been tested. Two such techniques are limited-entry perforating and sliding sleeves/fracture ports.

Limited-Entry Perforating. When wells are cased and cemented, the simplest way to connect to the reservoir is to perforate. Consequently, for many unconventional reservoirs, companies often use the limited-entry, plug-and-­perforate technique. Even though limited-entry design is relatively straightforward, its effectiveness depends on the rigor of the design, the fracture-fluid and proppant properties, appropriate zone grouping practices, and the perforation strategy itself.

In addition to optimizing limited entry, it is also critical to optimize the entire completion system for shorter fracture cycle time. For example, the entire completion can be optimized by using one-run wireline-conveyed millable composite bridge plugs and multistage perforation guns to reduce cycle time. This technology is particularly suitable for multiwall-pad completions.

Other enabling technologies include

  • High-pressure, sand-tolerant composite fracture plugs
  • Pump-down wireline and flow-through bridge-plug systems
  • Limited entry perforating charges and techniques
  • Downhole mills run on production tubing using snubbing rigs

Fracture-Sleeve Diversion. A relatively recent innovation, which is highly optimized for horizontal-well completions, is the ball-drop, sliding-fracture-sleeve system, as shown in Fig. 4. In these systems, a series of graded balls is pumped between fracture stages to open successive sleeves, from the toe to the heel. This system eliminates the need for setting plugs and perforating. As a result, the fracture operation is a continuous one, which saves considerable time and costs. Openhole systems are limited in the number of fracture stages by the ball sizes. Current systems that use balls with 1/16-in.-diameter gradation can deliver up to 35 stages. However, maximum stimulation pump rates are limited through the smaller ports and there can be incremental drilling costs because of borehole-size and -quality requirements. These systems can be installed in open holes and cemented in place to eliminate the need for packers.

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Fig. 4—Schematic of a ball-drop/fracture-port system.

Fracturing Fluids and Proppants

Selection of fracturing fluids and proppants is important for maximizing conductive fracture lengths and heights. Shell’s philosophy is that the optimal fracturing fluid and proppant is dependent on the subsurface properties and completion design. Each field pumps fracturing fluids that are tailored to the specific subsurface and operational conditions. In general, most fracturing fluids for UG, LRS, and LTO must meet the following criteria:

  • Minimize health, safety, and environmental effects.
  • Prevent clay swelling, fines migration, and emulsions or incompatibility with reservoir fluids.
  • Maximize fracture cleanup.
  • Achieve desired fracture height and length.
  • Be able to recycle and reuse fluids and reduce pumping costs.

Field-specific geochemical and geomechanical data are analyzed, and each field is matched to an optimized fracturing fluid. Fracturing fluids pumped in various fields include slickwater, gelled water, gelled oil, gelled propane, nitrogen-foamed water, polycarbon dioxide foam, pure carbon dioxide, and acid (including viscosity-diverted acid).
Proppants are chosen on the basis of formation-specific rock mechanical and chemical properties and the resulting fracture conductivity, estimated ultimate recovery (EUR), and cost. The full well life cycle is considered to maximize long-term production without overcapitalization. Proppants pumped include high-strength ceramics for deep wells, resin-coated sands to control proppant flowback and fines migration, natural sand, and ultralightweight high-strength plastics with a density close to that of water.

Conclusion

UG, LRS, and LTO plays will be a major part of the global energy industry for many years to come, and we are just scratching the surface of this unique and complex challenge. To meet this challenge, more than ever, rapid integration across all disciplines—from subsurface to wells and facilities—is required for success. Furthermore, technology should be considered a key enabler for reducing exploration and development costs, increasing well EUR, and mitigating health, safety, and environmental risks. The sooner technology is deployed in the exploration and development life cycle, the more substantial the effect from major economies of scale will be, considering that the benefits are multiplied by hundreds to thousands of wells.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163988, “Practical Insights and Benefits of Integrating Technology Into Exploration, Appraisal, and Development of Unconventional Gas and Liquid-Rich Shale Reservoirs,” by Bora Oz, SPE, David Braun, SPE, Sanjay Vitthal, SPE, Viannet Okouma, SPE, Mathieu Molenaar, SPE, Chandran Peringod, SPE, Sergei Kazakoff, SPE, Yongyi Li, Michele Asgar-Deen, and David Langille, SPE, Shell Canada, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28–30 January. The paper has not been peer reviewed.