SPE 162534

Optimized Shale Resource Development: Proper Placement of Wells and Hydraulic Fracture Stages Robert L. Kennedy, SPE, Rajdeep Gupta, SPE, Sergey Kotov, SPE, W. Aaron Burton, SPE, William N. Knecht, SPE, and Usman Ahmed, SPE, Baker Hughes

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition & Conference held in Abu Dhabi, UAE, 11–14 November 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

During the past six years, the technology for shale gas/oil developments in North America has seen many improvements and optimizations as the industry experiences a sharp rise in the contribution of hydrocarbons from these resources. More recently, Europe and Australia have joined the US in expanding recoverable hydrocarbons from these unconventional resources, and initial activities are on the rise in Latin America, China, Saudi Arabia and India. Despite such improvements and optimizations, a closer look at the performance reveals that not all wells are producing commercially. In addition, the hydraulic fracture stages are not all contributing within the producing wells. This scenario potentially suggests that it is important to target the field’s sweet spots while dealing with shale resources (like most other hydrocarbon-bearing formations). Hence, resource development based on the current concepts of geometric placement of hydraulic fracture stages (e.g., using fixed well/fracture spacing) may not be appropriate to develop such heterogeneous unconventional resource basins. In the discussion we illustrate certain well-defined criteria that can identify the sweet spot locations within a field/basin for the optimal well placement. We further document the vital formation/zone characteristics that define the locations for hydraulic fracture stages and thus move away from the arbitrary geometric placement.

The paper will discuss the well-placement optimization process and identify the required combination of proposed special petrophysical, geochemical, and geomechanical investigations (wireline, Logging While Drilling and cores). The hydraulic fracture stage placement analysis as presented, shoulders on the need to understand the existing natural fracture system. This understanding is achieved through geophysical log measurements and comprehensive analysis of the hydraulic fracture development pattern, as well as interaction of hydraulic fractures at each stage with the natural fractures. A naturally fractured reservoir can be drained more efficiently if a complex fracture network can be created by the hydraulic fracture stimulation. This begins by drilling the well in the direction of minimum principle horizontal stress in the area.

The paper concludes by presenting examples demonstrating the practical application of some of the specific aspects of the methodology discussed and with a number of specific conclusions. In summary, the three key points to Proper Placement of Wells and Hydraulic Fracture Stages, in order to maximize the net value of an operator’s asset are:

1. Begin With a Complete Understanding of the Reservoir 2. Use a Multidiscipline and Integrated Approach Across Each Phase of the Life Cycle 3. Effectively Use Modern Technology

Introduction During the past six years, the technology for shale gas/oil developments in North America has seen many improvements and optimizations as the industry experiences a sharp rise in the contribution of hydrocarbons from these resources. Figure 1 shows that the average shale gas production from horizontal wells has increased every year from 2006. The production profiles data were prepared from information from the “Drilling Info” database. The plotted curves represent an average production plot (all brought back to “0” time for direct comparison) from the major unconventional plays in North America.

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Figure 1-Horizontal Shale Gas Well Averages by Year

Although significant advancements in technology for the development of shale gas/oil plays in North America

(particularly in the US) have been made in recent times, a fair number of these shale (especially gas) wells still experience the relatively low Initial Productivity (IP). Gas IP’s tend to range anywhere from 2 to 10+ MMcfd, while shale oil IP’s fair better at 300 to 1900 BOPD. However, industry perception of what percentage of the frac stages (of the 10-20 stages placed in the average well) is producing is that only 40% of the stages contribute to all of the production from the well. Some operators have confirmed numbers in this range with Production Logging (PLT) or a very few cases with Distributed Temperature Sensing (DTS). The question begs, “What is the cause?” We have designed the best fracturing job possible, executed in the proper manner (and possibly used the same fluids and pumping schedule for the fracture treatment as was used on the offset well), run the best mechanical completion design, and yet many wells experience production rates that are not optimum. These authors believe that there are two possible reasons: 1. Frac placement did not intersect the natural fractures in the well, and/or 2. Reservoir quality (i.e., TOC levels, thermal maturity, and remaining hydrocarbon in the “source rock reservoir”) was low or nonexistent at the locations where fracture stages were placed. Reservoir quality is probably a significant part of the reason, which brings us to, “Has the well been placed in the area of the ‘sweet spots’ in the play?” Both of the reasons for wells not attaining the best IP and contributing production from more of the frac stages are investigated in this paper.

Many US operators do not invest in any methods of reservoir characterization along the horizontal lateral to assess

reservoir quality, i.e., no logs run, drilling cuttings not analyzed, and Advanced Mud Logging (with addition of gas chromatography) not used. Due to the significant numbers of offset wells in the major plays, have we been lulled into using the “cookie-cutter” approach because it is easy and does not require additional investment?

Although many US operators do not invest in some of the new available technologies, it has been found that

international operators in China, Latin America, Saudi Arabia, and India, who are just beginning to explore and exploit shale reservoirs, are eager to consider new technologies that have been shown to reduce cost or increase recovery. Also, these countries do not have the benefit of numerous offset shale wells that already exists in the US. We do not intend to imply that all US operators are discounting new technology. Majors, large independents, and other operators who recognize the economic advantage to a new technology will certainly consider and try it.

This paper will cover identification of sweet spots and other technologies and practices that are being used by some

operators to not only increase IP’s, but also attain higher ultimate recovery from shale wells. These practices center on use of the Asset Life Cycle approach first introduced by Kennedy, Knecht, and Georgi in 2012. Since the life cycle was covered in detail in this previous paper, it will not be rehashed again in this paper. Only the parts or recommended practices and methodology that cover well placement and effective hydraulic fracturing will be covered and in a summary form. Finally this paper will show examples of how the practices and methodology were successfully applied in certain wells.

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A number of specific conclusions are listed at the end of the paper; however they can be summarized by three key points to “Proper Placement of Wells and Hydraulic Fracture Stages” in order to maximize the net value of the asset for the operator:

1. Begin With the Complete Understanding of the Reservoir 2. Use a Multidiscipline and Integrated Approach Across Each Phase of the Life Cycle 3. Effectively Use Modern Technology

Shale Sweet Spots

Well-by-well production data indicate that shale formations have small spots of very productive wells (Sweet Spots), surrounded by large areas of wells that produce far less gas/oil. Sweet spots are a function of TOC, thermal maturity, thickness, GIP, natural fractures, mineralogy, and geomechanical stresses in the area. Sweet geologic spots may not necessarily be sweet economic spots. Also, if an area possesses most of these attributes, but is not a favorable area in which to frac (mineralogy or stresses), it is not considered as a sweet spot. It may sound trite, but develop the sweet spots first, then go back to the less attractive areas (Kennedy, Knecht, and Georgi 2012). The first step in identifying sweet spots is from information collected during a Basin Screening Study. It is recommended that these studies be conducted in a new basin or in a different part of a basin than currently being developed. The basin screening study should involve gathering and analyzing data including:

• Geology – sedimentology, statigraphy, and depositional environment • Geochemistry – TOC (initial reserve estimate), thermal maturity (type of hydrocarbon).

Is the shale a source rock? • Geomechanics – stress regime for well drilling and fracturing design and placement • Petrophysics – rock type, lithology/mineralogy, porosity (from logs and cores, a must) • Existing well data

To begin initial characterization of the reservoir, it is recommended that 3D seismic be conducted over the potential

play area. From 3D seismic the typical information on faults, formation thickness, depth, and lateral continuity can be obtained. However; 3D seismic can also be used to:

• Identify areas of highest TOC using acoustic impedance • Increase understanding of natural fractures using seismic attributes • Provide azimuthal anisotropy data related to natural fracture orientation and/or horizontal stress anisotropy • Assist in identification of sweet spots using seismic cross-plots

Data from exploration and appraisal wells is used to pin point the location of sweet spots through further formation assessment consisting of detailed mineralogical, structural, and geomechanical characterization (pulsed neutron spectroscopy, nuclear magnetic resonance, and acoustic logs). These data are more location specific, while information gathered through seismic is broad, spread out, and certainly not as accurate as that obtained from an actual wellbore penetrating the formation. The detailed discussion of this topic is included in the Optimizing Formation Evaluation and Reservoir Characterization section of this paper. Current Common Practices – Well Placement and Geometric Frac Placement This discussion will be divided into four parts: 1. Current Formation Evaluation and Lateral Characterization Practices, 2. Current Drilling Practices, 3. Current Hydraulic Fracturing Practices, and 4. Current Mechanical Completion Practices. Current Formation Evaluation and Lateral Characterization Practices

Many US operators will log and core vertical exploratory and appraisal wells to gather data for overall reservoir characterization; however very few operators run logs (wireline or LWD), analyze drill cuttings, or run Advanced Mud Logging operations (including gas chromatography) on development well horizontal laterals. There are two primary reasons: 1. Wireline logging the horizontal is somewhat problematical, and 2. Operators usually do not opt to incur the expense or risk involved. These operators do not invest in any means of reservoir characterization along the horizontal lateral to assess reservoir quality. Due to the significant numbers of offset wells in the major plays, perhaps we have been lulled into using the “cookie-cutter” approach because it is easy and does not require additional investment. As a result most hydraulic fracture stages are placed along the horizontal lateral solely on the basis of geometry (dividing the lateral length into an equal number of spaces or using some other arbitrary means of the same spacing that had been done in previous wells in the area). Current Drilling Practices

Due to the unique nature of shale, every basin, play, well and pay zone may require a different approach. Complex reservoir characteristics pose different drilling challenges related to well placement, wellbore stability, higher torque and drag, inconsistent build up rates, geological uncertainties, lost circulation zones and other issues. Drilling shale wells presents

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technical challenges that impact the overarching goal of optimizing drilling costs and reducing days on wells. The quality of pre-well planning impacts both drilling spend and ultimate recovery. Therefore, an integrated approach is required to ensure that all the available reservoir data, geoscience, and geomechanical knowledge and down-hole conditions are well understood prior to planning the details of shale wells.

Operators have already seen the benefits of horizontal wells in US shale plays. With the available modern horizontal drilling technology it is possible to efficiently drill and complete these wells. Figure 2 is a typical well profile for a Woodford Shale play. It is reflective of most wells in the gas plays. Listed below are typical practices used for drilling horizontal wells.

• Vertical Section - Build/Curve Section - typically 8deg/100ft to 12 deg/100ft • Lateral/Horizontal section - Length of horizontal sections varies from play to play, a range of 2500 to 7500 ft. • Most operators convert to some form of Oil Based Mud (OBM) prior to drilling the curve and lateral. • Typically, wells use drilling motors (positive displacement motors - PDM) to drill the vertical section. • In a cost sensitive environment motors are also used to drill the curve and the lateral sections. Sliding with a PDM

can be challenging due to tool face control and drag issues, which often results in lower ROP (Rate of Penetration) while drilling long horizontals and attempting to steer through the sweet spot of the reservoir. Although it is not impossible to drill and remain in the horizontal sweet spot using a PDM, there is a better way.

• A rotary steerable system (RSS) is typically more efficient in that respect because of continuous near-bit information and automatic steering capability (Discussed below in the Optimization section).

Figure 2-Typical well profile for a well in the Woodford Shale play

Current Hydraulic Fracturing Practices Though the importance of the “customized” hydraulic fracture design for each individual well is hard to overestimate,

a “cookie-cutter” approach is still quite common. This design methodology may be partly justified by the lack of the information required for the designing purposes and/or by the economics. The fact that the reservoir properties vary significantly, not only vertically, but also aerially along the lateral, creates additional challenges for the “optimum” treatment design. It is difficult to model the fracture complexity in the naturally fractured formations even with the use of the modern fracture simulators. The variations and the uncertainty in the geomechanical and petrophysical properties complicate this challenging task even further, therefore some operators opt for the completion and stimulation design, which was previously proven to be successful in an offset well, in a different part of the field or even in a different formation

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Due to a great variety of rock properties and significant variations in stimulation treatments of different shale plays, it is “unfair” to summarize the trends, common practices and rules of thumb. However, we have included Table 1 which shows the typical fracturing treatments of some of the major shale plays. A completion strategy and a hydraulic fracture design should be localized and limited to a certain area within a particular shale play. For example, the variations for the stage spacing and number of clusters are quite significant: from 150 ft to 750 ft spacing (250ft to 350 ft is used most frequently) between stages, and from 3 to 8 clusters per stage, in the cemented (cased hole) plug-and-perf type of completion. The same applies to the packers and sliding sleeves (Ball-activated completion methods) in open-hole completion: spacing differs based on the experience in a certain area. Unfortunately, the industry has tended to use the arbitrary geometric method of placing frac stages along the horizontal laterals of shale wells.

Table 1–Typical Fracturing Treatments of Some of the Major Shale Plays

Quite often poor production from some shale wells is blamed on the completion and the fracture treatment. However, industry perception of what percentage of the frac stages is producing is that only 30-50% of the stages contribute to the total production from a shale well. Several technical publications presented data demonstrating that production logging tools identify only 40% of the perforations contributing to the total production. In a very few cases similar numbers have been confirmed with Distributed Temperature Sensing (DTS). The question begs, “What is the cause?” We have designed the best fracturing job possible, used the same fluids and pumping schedule for each stage in a multi-stage hydraulic fracture treatment as the offset well, run the best mechanical completion design; and yet many wells experience production rates that are not optimum. These authors believe that there are two possible reasons 1. Frac placement did not intersect the natural fractures in the well, and 2. Reservoir quality (i.e., TOC levels, thermal maturity, true source rocks) was low or nonexistent at the locations where fracture stages were placed. Reservoir quality is probably a significant part of the reason, which brings us to, “Has the well been placed in the area of the ‘sweet spots’ in the play?”

Current Mechanical Completion Practices Three types of completions have proven to be the most effective and efficient in the North American shale plays (Table 2). These are plug-and-perf, ball-activated systems, and coiled tubing-activated systems.

Completion Type Fluid Diversion Through-tubing Isolation Annular Isolation Plug-and-Perf Perforations Composite Bridge Plugs Cement Ball-activated Frac Sleeves Frac Ball and Ball Seat Openhole Packers Coiled tubing-activated Frac Sleeves Coiled Tubing Packer Cement

Table 2-Comparison of three common types of shale well completions

Plug-and-Perf (Figure 3) uses perforations to divert the frac fluid, composite bridge plugs to isolate the fracture through the tubing, and cement to isolate the annulus of the openhole and liner string. Ball-Activated systems (Figure 4) use frac sleeves containing ball seats that correspond to different size frac balls. When the frac balls are pumped onto the seats, pressure opens the sleeve to divert the frac, and the ball also provides through-tubing isolation from the previously fractured stage. Annular isolation is achieved by using openhole packers. Coiled Tubing-Activated systems (Figure 5) use frac sleeves that are opened by means of coiled tubing. Through-tubing isolation is achieved with a coiled tubing packer and annular

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isolation is accomplished with cement. The recent technology advances for these types of completions have resulted in a variety of hybrid systems as well. These hybrid completions can use either cement or openhole packers for annular isolation.

Figure 3-Plug-and-Perf Completion System – Cased Hole

Figure 4-Ball-Activated Completion System – Openhole

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Figure 5-Coil Tubing-Activated Completion System – Cased or Openhole

Optimizing Well Placement and Hydraulic Fracturing This discussion will be divided into five parts: 1. Brief Review of the Asset Life Cycle, 2. Optimized Formation Evaluation and Reservoir Characterization, 3. Optimized Drilling, 4. Optimized Hydraulic Fracturing, and 5. Optimized Mechanical Completion; all of which focus on the placement of shale well and hydraulic fracture design and placement for best IP (Initial Productivity) and ultimate recovery from the well. Asset Life Cycle The Asset Life Cycle is the platform adopted by our company as the suggested method for operators to use when analyzing, developing and producing unconventional shale gas/oil reservoirs. The Asset Life Cycle, Figure 6, includes five phases – A. Exploration, B. Appraisal, C. Development, D. Production, and E. Rejuvenation. Most of the terms have been around the industry for a number of years, and are not new with the exception of possibly the Rejuvenation phase. What is new, however, is the technologies and solutions that are employed and the operator objectives to be accomplished during each phase.

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Figure 6-The Shale Gas /Oil Asset Life Cycle

A. Exploration Phase Objectives

• Conduct a basin/area screening study to identify core areas (sweet spots) and to determine an initial estimate of Gas/Oil In Place

• Begin to characterize the reservoir • Determine the initial economic value and reservoir potential / Evaluate

B. Appraisal Phase Objectives

• Drill the appraisal wells • Build reservoir model(s) for simulation • Generate a Field Development Plan • Validate the economics of the play /Evaluate • Pilot Project? / Evaluate

C. Development Phase Objectives

• Implement the Field Development Plan • Install surface production and export facilities, including compression and pipelines • Design wells and optimize drilling costs • Refine and optimize the hydraulic fracturing and well completion designs

Exploration

Appraisal

Development Production

Rejuvenation

Asset Life Cycle

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D. Production Phase Objectives • Monitor and optimize producing rates • Manage the Water Cycle – Sourcing for drilling and fracturing water, well flowback water, lifting, treating,

handling, and disposal of water • Reduce corrosion, scaling, and bacterial contamination in wells and facilities • Protect the environment

E. Rejuvenation Phase Objectives The Challenge for the Rejuvenation Phase is to remediate low-rate and sub-economic wells.

• Evaluate wells for Re-Frac candidates • Analyze field for re-development potential - Infill Drilling

Life Cycle (above) is slightly modified from that which was first introduced by Kennedy, Knecht, and Georgi (2012).

The optimization process for well placement and hydraulic fracturing includes following steps from the Asset Life Cycle: • Conduct a basin screening study to begin to identify location of sweet spots • Conduct formation evaluation (cores and logs) on exploratory and some appraisal wells to characterize the

reservoir • Drill both vertical and horizontal appraisal wells to gather reservoir data and test the fracture/mechanical

completion designs for well productivity • Optimize well drilling cost, procedures, and placement • Run logs, drill cutting analyses, and full mud logging on the horizontal laterals of development wells • Optimize the hydraulic fracturing design and placement • Optimize the mechanical completion

All of these steps can be summarized by three key points (from these authors) for “Proper Placement of Wells and

Hydraulic Fracture Stages” in order to maximize the net value of the asset for the operator: 1. Complete Understanding of the Reservoir 2. Multidiscipline and Integrated Approach Across Each Phase of Life Cycle 3. Effective Use of Modern Technology

Optimized Formation Evaluation and Reservoir Characterization

Optimum methods of characterizing rock mineralogy, TOC (Total Organic Carbon Content), and the natural fracture network are discussed in this section. The mineralogical characterization and TOC quantifications mainly rely on a pulsed neutron spectroscopy and nuclear magnetic resonance (NMR) logs. The processing of capture and inelastic gamma ray spectra obtained from the pulsed neutron tool can quantify the formation’s basic elemental composition, including silicon, calcium, aluminum, iron, sulfur, magnesium, and carbon (Certain tools can identify as many as 18 elements plus the most important carbon). Geomechanical characterization is based on acoustic and density log responses. Variation in the reservoir mineralogy and TOC content affect the rock mechanics properties. Stress vs. strain curves can be derived from micro-mechanical models of the rock which enable correlations between dynamic (obtained from acoustic logs) and static elastic properties (obtained from triaxial compression testing on core samples). Additionally, the azimuthal and transverse shear wave anisotropies can be processed from a cross-dipole acoustic log to characterize the vertical and horizontal rock stiffness. This anisotropic characterization of the rock enables the evaluation of the fracture gradient and stress contrast between the target formation and the overlying and underlying formations (Franquet, Bratovich, and Glass 2012).

An example of a pulsed neutron spectroscopy log used for mineralogy characterization and analysis technique is

shown in Figure 7, and described below by Mitra et al (2010).

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1 2 3 4 5 6 7 8 9 10 11 12 13

Figure 7–Integrated Shale Analysis Plot from the Barnett Shale

Figure 8–Mineralogy Legend for Interpreting Lithology and Mineral Track (Figure 7) Tracks 8 and 9 (Integrated Shale Analysis plot of a well from the Barnett shale) show the results of the

shale gas facies system applied to this well. Track 8 represents the lithofacies (mineralogy) from the Barnett model. The organic-rich shale lithofacies is shown in black, the non-siliceous organic-rich shale is shown in orange, the low organic shale lithofacies is shown in gray, the siliceous mudstone lithofacies is shown in yellow, the calcareous mudstone lithofacies is shown in blue, the phosphatic zone lithofacies is shown in light green, and the pyritic zone lithofacies is shown in red (Figure 8). Track 9 represents the “stop-light” component of the shale gas facies expert system, where favorable frac zones are marked in green and unfavorable frac zones are marked in red. The predominant lithofacies in the Barnett shale is the siliceous mudstone followed by the organic-rich shale lithofacies. Track 10 provides information on frac migration, Track 11 geomechanical properties and Tracks 12 and 13 information on anisotropy.

This shale gas facies expert system provides operators with a quick and accurate method of classifying shale gas reservoirs, identifying favorable zones for hydraulically fracturing, identifying frac barriers and locating zones from which to drill horizontal laterals. The analysis and expert system can also provide log-derived rock mechanical properties and uses porosity and TOC for the calculation of G/OIP (Gas/Oil In Place). Further discussion can be found in Jacobi et al 2009; LeCompte et al 2009; Pemper et al 2009; Mitra et al 2010; and Franquet, Bratovich, and Glass 2012). It should be noted that cores are a must, either conventional or rotary sidewall cores for analysis and direct measurement of certain parameters and to calibrate logs for the specific area.

The primary objective of these types of logging surveys and analyses is twofold, 1. Determine the most optimum

locations in the well to place hydraulic fracture stages, and 2. Determine the most optimum location in which to place the horizontal lateral. The hydraulic fracture should be initiated in the most “fracable” (most brittle mineralogy) locations, so more energy can be used to propagate fractures and create more complex fractures. In addition, these locations should also have the higher TOC’s in the well; thus they are targeted at the sweet spots. These types of logging surveys and cores are normally only run or taken in vertical wells. From the numerous mineral spectroscopy logs that have been run in shale wells,

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it is known that geochemistry (primarily TOC), lithology, and mineralogy can vary foot by foot both vertically and laterally in shale reservoirs. These authors recommend that reservoir characteristics should be determined along the horizontal laterals. Initially, the purpose is to determine the optimum placement and spacing of hydraulic fractures and perforation clusters (in plug-and-perf completions), and ultimately to maximize production and recovery. Some tools are available for use in a Logging While Drilling (LWD) mode; however, currently LWD or their wireline equivalants are infrequently used or always available to gather all the information that could be obtained.

One aspect of the definition of sweet spots is the existence and location of nature fractures. One of the objectives of the hydraulic fracturing is for the induced stage fractures to intersect natural fractures in a perpendicular or transverse manner. Thus, a naturally fractured reservoir can be drained more efficiently if a complex fracture network can be created by the hydraulic fracture stimulation. Natural fractures can be identified and located along a specific well horizontal lateral by the use of LWD resistivity imaging tools. In addition to locating natural fractures along the lateral wellbore these tools can also identify induced fractures (from nearby offset wells), bedding planes, faults, and provide information for wellbore integrity to identify breakouts. LWD resistivity imaging is discussed in detail in the Optimized Hydraulic Fracturing section found later in this paper. Optimized Drilling

For optimized drilling there were two main innovations of Rotary Steerable Systems (RSS): • Continuous Drill string Rotation while Steering • Highly Automated Steering Control and Easy Directional Target Changes via surface command

These two elements combined offer a wealth of improvements to drilling efficiency. Other advantages of RSS are listed below.

• Increased Rig Efficiency – No orienting and sliding: Greater net ROP – Optimized bit selection for performance

• Greater Reach Capacity – Better weight transfer with continuous pipe rotation – Less friction with smooth 3D well trajectory and superior gauge hole quality – Tight TVD control over long intervals

• Increased Production – More Precise wellbore placement in the reservoir – Effective Reservoir Navigation Service with integrated sensors and easy directional control

• Reduced Drilling Risk – Continuous rotation and smooth wellbore improve hole cleaning – Continuous rotation reduces risk of differential sticking

Today with the advancement of modern drilling technology we are able to drill the build/curve section and the lateral section in “one single run” using the High-build rate RSS system (Figure 9).

Figure 9–High-Build Rate Rotatary Steerable System

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The High-build Rate RSS provides the following advantages. • One BHA (Bottom Hole Assembly) Configuration for All Intervals

- Oriented Kick Off from Vertical - Controlled Vertical drilling with a Rotary BHA - Drill the Curve up to 12 degrees per 100 ft build rate - Drill the Lateral precisely and fast

• Eliminate BHA Trips • Higher bore hole quality • Reduce days on wells

Once the target zone has been identified it is important to place the well bore in the optimal part of the reservoir following the natural dips in the formations and moving to follow faults. With today’s modern MWD (Measurement While Drilling) and LWD tools it is possible to use reservoir navigation services where engineers use the shale analysis with available seismic and offset well data to plan the trajectory of the well bore. During drilling the LWD data is monitored by experts located in remote drilling centers and modifications are made to the trajectory to maintain the well bore in the optimal zone and in the sweet spots. Azimuthal LWD images help to obtain a 360 degree view of the well bore in real-time and decisions being made on the fly while drilling the lateral section to keep the well within the productive zone (Figure 10). The importance of a high quality hole cannot be emphasized too much. Poor quality boreholes will, in many cases, lead to a poorly completed well or one where significant amount of repair must be undertaken prior to well completion. Hole quality can be evaluated early and corrected during the drilling of the well. Near bit inclination and caliper measurements are two examples of data that can then be used to correct drilling parameters and improve the overall well quality, stability, and placement, ensuring maximum effective reservoir exposure for optimum production. Drilling, formation navigation, well placement and orientation (with respect to minimum stresses) are all important for obtaining optimum production and recovery. These authors recommend the use of optimized drilling practices and employing High-build rate RSS for optimum and cost effective well placement in shale reservoirs. The resulting wells will attain maximum reservoir exposure by placing them in the sweet spots.

Figure 10–Reservoir Navigation to Stay in the Zone and the Sweet Spot Optimized Hydraulic Fracturing Numerous publications address the optimization of the fracturing process, but some questions on the actual treatment design still remain. However, the design will vary depending on the specific shale play formation type and characteristics. These questions include:

1. Number of stages 2. Stage placement (location along the lateral and spacing) 3. Number of clusters (plug-and-perf)

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4. Perforation size and number to ensure fluid diversion 5. Fluid type or combination of different fluids 6. Proppant types and concentrations 7. Pumping rates 8. Fluid and proppant volumes 9. Plus others

There are certain challenges in fracturing unconventional reservoirs: • Fracture geometry

- Fracture azimuth - Not creating expected length

- Brittle or ductile rock – complex or simple fracture network • Proppant transport

- Proppant falling out of zone - Proppant pack not connected to perforations - Proppant distribution in the fracture

• Final conductivity - Gel damage, breaker/clean-up issues - Proppant crushing, embedment, multiphase flow

• Reservoir properties - Not as expected

• Geohazards - Growth out of zone, faults, karsts, and wet zones Overcoming all of these challenges will certainly lead to the “optimum fracturing treatment;” however, the objective

of this paper is to provide the guidelines for the proper placement of the fracturing stages/perforation clusters in order to move away from the current practice of arbitrary geometric placement. The following discussion will cover other pertinent hydraulic fracturing topics specifically related to creating the more complex fractures that are required for unconventional wells.

A comprehensive summary of shale development evolution is presented in the frequently cited “Thirty years of Gas

Shale Fracturing: What Have We learned?” paper by King (2011). This paper describes shale gas reservoir development history, and is also considered as a great source of information for shale oil. Although fundamentally similar to fracturing vertical wells, horizontal well fracturing has unique aspects that require special attention to ensure successful treatment. s Reservoir models show that, as opposed to the conventional fracturing with a bi-wing single plane fracture geometry, a naturally fractured reservoir can be drained more efficiently with a complex fracture network. The difference between the two concepts for the desired fracture geometry has been described by many authors in the technical literature. In horizontal wells, as in vertical wells, the fracture azimuth and dip are controlled by the in-situ stress tensor. The understanding of the local stress regime will determine the optimum horizontal wellbore azimuth, which will facilitate the control of the fracture orientation relative to the wellbore axis. The relative deviation between the well and stress field may also cause tortuosity (as the fracture propogates), resulting in higher initiation and treating pressures, and lower near wellbore conductivity.

The knowledge of the in-situ stress is critical for the successful fracture placement. The complexity of the fracture

network may be achieved by multi-stage fracturing with low viscosity fluid, provided that the reservoir properties “allow” the fracture complexity to develop. High-rate slick water fracturing creates tensile fractures as well as shears the existing fractures in the brittle shale formations with low horizontal stress anisotropy. Slickwater fracturing has become the norm in the Barnett and Marcellus shale plays.

The industry has developed a method for creating even more complex fracture system: simultaneous and zipper

fracture treatments (See Figure 11). They are performed on the adjacent parallel wells in order to create a more complex fracture network, contacting much greater surface area as opposed to individually fractured single wellbores. Simultaneous fracturing is a stimulation treatment of two or more horizontal wells at the same time. This type of treatment can also be performed on different locations as long as the horizontal wellbores are parallel and relatively close. Zipper fracturing is an alternating fracture treatment method on two offsetting wells. The stimulation and perforation operations alternate on both wells. While a stimulation crew is performing a fracture treatment on one well, the other crew is isolating the stimulated zone with a plug and is perforating the other zone in the other well. Then the frac crew rigs up to the well, which has just been perforated, and performs the hydraulic fracture stimulation while the other well is being perforated. In addition to the efficiency of the fracturing operation and time reduction, it is believed that zipper fracs create more fracture complexity.

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Figure 11-Schematic view of stimulation procedures. Figure 12-Combined Microseismic Wells A & B were stimulated simultaneously – “Simulfrac.” monitoring results for wells A-E Wells D & E were stimulated sequentially - “Zipper Frac” (Vermylen and Zoback 2011)

It is interesting to note the conventionally fractured well, and two alternately fractured wells (“zipperfracs”) were

more effective than the simultaneously fractured wells (“simulfracs”) in generating microseismics (Figure 12). It is possibly related to poroelastic effects from the large amount of pumped water during the successive stages that control the stress change in the reservoir (the simulfracs were pumped in half the total time than the zipperfrac wells with less time for pressure to leak-off). It was also found that the later stages of fracturing a given well were more successful in generating microseismic events (Figure 12) than the early stages. This increase in “micro-earthquake” activity in the latter frac stages corresponds with the increase in the instantaneous shut-in pressure. Figure 13 is an example of one of the studies of simultaneous and zipper fracture treatments in the Barnett shale showing five parallel wells analyzed with the total of 51 frac stages (Vermylen and Zoback 2011). Although these authors believe that this phenomenon should be further investigated, it does offer another means of developing complex fractures.

Figure 13-Instantaneous Shut In Pressures escalate from toe to

heel in all wells. The simulfrac wells, A&B, escalate the most, while zipperfrac wells, D&E escalate the least.

Fracture complexity of the hydraulic stimulation is highly desired. The Barnett shale is one of the best examples of a successful application of slick water fracturing. No two shales are alike (King 2010), and there is no other shale exactly like the Barnet; i.e., with the identical rock properties. Other ultra-low permeability reservoirs require a unique completion and stimulation strategy.

In cases in which the natural fracture network is deemed of secondary importance to productivity, drilling the well in the direction of maximum principle stress is preferred in order to favor the creation of longitudinally-trending hydraulic fractures. Longitudinal fractures reduce radial convergence by maximizing exposure of the wellbore to the hydraulically-

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created fracture and usually eliminate the need for high-conductivity proppants (Cramer 2008). It has been found that the Niobrara is an example of this; i.e., low numbers and presence of natural fractures.

Although slickwater fracturing has proved itself in a number of US shales, there are many cases where slickwater fracturing has not provided sufficient propped flow capacity to develop a gas or oil productive shale. For these cases, a hybrid fluid using a slickwater frac to open the fissures and a more viscous fluid to place the main body of the proppant may be warranted (King 2010).

Selection of the fracturing fluids is very important for the successful hydraulic fracture stimulation treatment. There

is a wide variety of fracturing fluids, and the optimum one must be chosen depending on the shale reservoir type, i.e., dry gas, wet gas, or oil. Table 3 compares suggested fracture treatment types for dry gas, wet gas, and oil. The industry continues to optimize fracturing fluids, improving the performance of the fluids and addressing environmental concerns.

Table 3–Suggested Fracture Treatment Types for Dry Gas, Wet Gas, and Oil

Low viscosity slickwater fluids generate fractures of lesser width and therefore greater fracture length,

theoretically increasing the complexity of the created fracture network for better reservoir-to-wellbore connectivity. Unfortunately, slickwater fluid is an inherently poor proppant carrier, necessitating high pump rates to achieve flow velocities sufficient to overcome the tendency of the proppants to settle. Advanced fluid technologies combine the best attributes of slickwater and conventional crosslinked fluids systems to maximize proppant transport through the surface equipment and long laterals, before breaking to create a desirably complex fracture network (Brannon and Bell 2011).

To enhance the proppant placement in a low viscosity fluid, light weight and Ultra-light weight (ULW) proppants

may be considered, providing more improved effective fracture length than can be achieved with conventional proppants. The improved transport efficiency of ULW proppant has been proven in field application to enable placement in partial monolayer concentrations to create high conductivity fractures. In addition, the transportability of ULW proppant has been shown to provide a greatly increased effective fracture area (Brannon et al 2009). There are a number of other proppant transport challenges, but they are not the focus here, nor will they be discussed in this paper

Multi-stage fracturing requires a significant amount of water. Water availability has become a worldwide concern.

To address the water shortage issue, the industry has identified the alternatives to fresh water. These include: recycled water (treated flowback water), produced water (treated), formation water (water source wells), and/or sea water. Many companies are re-evaluating these resources as a cheaper and better base fluid for frac fluid. In areas with developed oil and gas infrastructure, the cost of processing and using this fluid for fracs is both economically and technically attractive to scarce fresh water (King 2012).

A general belief that oil wells require more conductivity than gas wells is due to the fact that oil is less mobile than

gas. Hydrocarbon mobility plays a key role in the productivity of a particular reservoir rock/pore fluid system. It can also affect stimulation design – multiphase oil production requires significantly greater fracture conductivity than what is accepted for single-phase gas production (Shaari, Minner, and Lafollette 2011). Although slickwater provides very poor proppant transport, with high pumping rates, substantial fluid volumes, adequate proppant selection and pumping schedules; slickwater treatments may enhance gas production better than x-linked fluids for these particular reservoirs. Slick water treatments appear to be more successful in the hard brittle rock with low horizontal stress anisotropy. Hybrid or x-linked types of treatments may be considered for oil wells to provide better fracture conductivity.

There are several methods of fracture treatment monitoring, including but not limited to: tilt meters, microseismic

monitoring, distributed temperature sensing (DTS), radioactive and non-radioactive tracers, pressure monitoring, production logging. Currently the most frequently used/effective monitoring method is microseismic monitoring. The objective of microseismic monitoring is to determine the fracture geometry, azimuth, and major fracture orientation (in near real-time),

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validate the stress profile, and estimate the Stimulated Reservoir Volume (SRV). All of these data provide an understanding of the zonal coverage. The geomechanical model, reservoir model and fracture stimulation model, along with multiple diagnostics such as surface tilt meters and downhole microseismic monitoring, will provide the ground for a sound engineering solution - how to optimize the spacing between the stages, the number of clusters required, and overall treatment design. Fracture modeling, design, and post treatment diagnostics (history matching) are also the important factors in the optimization of the stimulation treatment. A number of US operators are running microseismic on every frac job (at least those where a nearby observation well is available).

Stage size and cluster spacing is an important design variable to create contributing transverse fractures along the horizontal wellbore, but often fluid loss and mechanical interaction of the created fractures is overlooked. There are two factors to consider when deciding on stage size and cluster spacing: 1) the physics of creating multiple transverse fractures and 2) the longer term production interference (interaction) of those fractures. Bazan, Lattibeaudiere, and Palisch provide some information on this in their 2012 paper. Several other publications discuss the above topic (Meyer and Bazan 2011; Cheng 2010; Song, Economides and Ehlig- Economides 2011; Jo 2012; and Bhattacharya and Nikolaou 2011).

Although the authors recognize the importance of integrating the fracture model with geomechanical and reservoir

models—to optimize the completion and stimulation strategy—it is not the focus of this paper. Tools for characterizing certain reservoir information along the lateral, such as high definition electrical resistivity imaging LWD tools, are providing valuable information for placement of frac stages and perforation clusters (in plug-and-perf) for well completion. Where do images fit? Figure 14 shows that 3D Seismic has limited resolution and cores have limited coverage; therefore, high definition resistivity images truly fill this gap.

Figure 14–Where do Images Fit?

High definition resistivity images can identify natural fractures, induced fractures (from nearby offset wells), faults, and bedding planes. This information can be used to help optimize the fracturing (placement) program, avoiding areas where fracturing will be inefficient and, more importantly, identifying areas where fracturing is most beneficial; i.e., locations of Natural Fractures (See Figures 15 and 16).

Figure 15–How Image Colors are assigned.

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Figure 16–The LWD Resistivity Imaging Tool Provides Valuable Information on Frac Placement.

There are other benefits of LWD resistivity imaging in the shale plays:

• Hazard Mitigation (for wellbore integrity) - to identify breakout and drilling induced fractures. Information can be used to make adjustments to mud weight. Proper mud weight will prevent the wellbore from caving in and sticking of the BHA or prevent the formation from fracturing and subsequent mud losses.

• Wellbore Placement/Reservoir Navigation - to determine structural dip and dip azimuth to optimize real-time wellbore placement in the most productive interval of the reservoir

It should be noted that resistivity imaging tools require drilling the well with a conductive fluid (WBM) in order to obtain reliable high quality image data. It has been observed for most shale wells in the US, the drilling fluid is converted to some form of OBM prior to drilling the curve and lateral. With the advancement of WBM fluid technology and its environmental friendly characteristics, in the US, we have started to see acceptance of WBM to drill the lateral section which has proven cost effective to using OBM.

LWD imaging is a significant step to beginning to characterize the horizontal lateral and moving away from the

arbitrary geometric fracture stage placement. Imaging provides important information about fractures and hazards along the lateral (resulting in increased production rates where stages have been moved or altered as is described in the Example section of this paper). These authors, however, propose the addition of Advanced Mud Logging (including gas chromatography) and cuttings analysis in order to provide mineralogy, TOC content, and rock mechanical properties. This will fully characterize the lateral for totally optimizing frac stage placement for optimized production and recovery, as well as calculation of G/OIP. In a very few wells mineral spectroscopy (to obtain complete mineralogy including log-derived geomechanical properties and TOC) tools have been run in the horizontal lateral with wireline and the use of tractors or coiled tubing. Few operators have opted for this costly and possibly problematic logging method.

Optimized Mechanical Completion Each completion technique has its own unique benefits, and there is no “silver bullet” when it comes to unconventional completions. There are a number of benefits and considerations for each technique, but that is not the focus of this paper. Only the features that stand out will be discussed. Also, several other factors must be considered, including frac water, additives, proppant supply, availability of services, operator owned services, and overall economics for the operator. The Appraisal phase is the time to gather as much data as possible to determine where the sweet spots are, and where to actually place the fracture stages (previously discussed). Plug-and-perf has a distinct advantage during this phase. The stage placement has not been locked into place until the perforation gun has been fired into the liner string. If it is determined that a stage needs to be moved to another location along the lateral, it is simply a matter of moving the perforations to that depth. This allows time for data gathering, and changing the stage placement on the fly, if required. There is, however, a lack of efficiency during the fracturing process, because of rigging up and rigging down of wireline and pressure pumping equipment between each stage. When operators move into the Development phase, this is the time to focus on more efficient completion techniques, dependent on the economics and availability of services. Simultaneous operations can be utilized in some applications to optimize plug-and-perf completions (the “Simulfrac” process was previously discussed). If two wells are spaced close enough together, wireline can be operating on one well while pressure pumping is operating on the other. When

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both operations are complete, the services switch wells and minimize the nonproductive time for both wireline and pressure pumping. Ball-activated systems are primarily used for completion optimization, because of the efficiency and logistical benefits during the fracturing process. These systems are simpler from a logistical point of view, because pressure pumping is the only service that is required on location. Also, the frac job does not shut down between stages, because the frac balls can be dropped while the fluid is being pumped. The total time of the fracturing process is dependent on the frac plan, but in some instances 40 stages have been fractured in only 24 hours with ball-activated systems. The ball seats, however, do create an ID restriction. In most scenarios (as shale wells tend to be low flow rate) this is not an issue unless a screenout occurs. Therefore, this technique may not be the best choice during the Appraisal phase. Once operators reach the Development phase and are more familiar with the formation/reservoir, screenouts are less likely to happen. The ball-activated system can help drive efficiency during the fracturing process, and allows for wells to come on production faster than with plug-and-perf. Coiled tubing-activated systems offer accuracy and contingency options during the frac process. The frac maintains efficiency, requiring only brief shut downs between stages to move the coiled tubing assembly to the next stage. Shutting down the fracturing allows for the most accurate fluid placement into each stage, which is significant in formations where overdisplacement of fluids is an issue. Also, the coiled tubing is already in the wellbore. If a screenout occurs, this would keep nonproductive time to a minimum. This system can actually allow a more aggressive frac design. The frac is performed through the annulus of the coiled tubing and the liner string; therefore, the fracturing ID is significantly reduced. This completion system is dependent on coiled tubing; therefore, depth and availability of coiled tubing at the same time as a pressure pumping crew can result in limitations on this type of completion. Because the coil-tubing activated system uses frac sleeves, the placement of the stage cannot be adjusted on the fly. If there is ample data to determine the placement of the stage before the well is completed, this system would be a viable option, especially during the Appraisal phase. Primarily, because the system offers the flexibility, should a screenout occur. If additional data gathering that could impact the placement of the stages will be performed after the completion is set, this may be a better option for completion optimization during the Development phase. Examples of Application of this Optimization Methodology Shale Formation Evaluation Case History, Woodford Shale, Oklahoma, US Jacobi et al (2009) in the SPE paper, “Effective Geochemical and Geomechanical Characteristics of Shale Gas Reservoirs from the Wellbore Environment: Caney and Woodford Shale,” describes the measurement of reservoir rock properties by using downhole (wireline) geochemical (mineral spectroscopy), acoustic, and NMR tools. Using this combination of tool measurements lithology, mineralogy and TOC were determined. The mineralogy, porosity, acoustic velocities, bulk density, pore pressure, and overburden stress were used to compute the unconfined compressive strength, Poisson’s ratio, and horizontal stress for each interval for three different wells in the Woodford shale. The results were used to develop hydraulic fracture design and stage placement. The fracture design goal in the Woodford is to achieve optimum width in vertical height growth, as well as to identify frac barriers that may prevent this. One of the three wells, the Newberry 1H-12, Atoka County, Oklahoma, was selected by these authors for follow up and continued case history on completion and production results as compared to five nearby offset wells. Figure 17 from Jacobi et al (2009) is a log of the Newberry 1H-12 well.

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1 2 3 4 5 6 7 8 9 10 11

Figure 17-Log of the Newberry 1H-12

Figure 17 shows model results with lithofacies (Track 9) of siliceous organic mudstones (black bars), carbonate

mudstones (blue bars), siliceous mudstones (yellow bars), low organic mudstones (grey bars), and low siliceous mudstones (orange bars) (See Figure 8 for Mineralogy Legend). Also, Track 10 shows the corresponding favorable fracture zones (green bars) as opposed to potential fracture barriers (red bars) within the Woodford, Sylvan, Viola, and Mayes formations. Note that the Mayes carbonate mudstones serve as fracture containment for the Woodford. The Newberry well contains significant siliceous mudstones, which are favorable fracture targets. A review of the GIP value (Track 7) indicates that gas production should be relatively high.

Information obtained from the IHS database indicates that the Newberry 1H-12 was drilled to a TD of

16,250 ft (TVD 13,201 ft), and completed in January, 2008. The TVD depth, which corresponds to the depth that the operator chose to place the horizontal lateral, has siliceous mudstone mineralogy (brittle, highly fracable), and is one of the intervals with the highest GIP value. The initial well test rate was 3,817 Mcfd compared to the average for the five offset wells of 2,330 Mcfd. Figure 18 is a production plot of the Newberry 1H-12 well and the five closest offset wells, which were all horizontals. All plots have been brought to “0” for comparison purposes. The offset wells have been assigned the numbers 1 though 5; however, these numbers do not relate to actual well names. Completion dates for wells were: Well 1H-12 – January, 2009; Well 1 – August, 2009; Well 2 – January, 2008; Well 3 – February, 2009; Well 4 – July, 2009; and Well 5 – September, 2010. Table 4 compares the number of frac stages, top and bottom of the total perforations, and total perforated lateral lengths for each well. All well completion and production data were obtained from the IHS database.

It can be seen that the Newberry 1H-12 well, with a rather complete formation evaluation conducted and used to

select the lateral placement, produced at higher rates than all of the five offset wells. The 5 Frac Stages were near the average number for four of the offsets, and the total perforated lateral length for the 1H-12 well was actually less than four of the five offsets. It should be noted that Well 5, with the 12-stage frac and second longest perforated lateral length, is the next best production to the Newberry 1H-12. The public IHS database does not include information as to whether or not any of the five offset wells had any formation evaluation analysis conducted, nor is it known if any logs for lateral characterization were run on any of the wells. Even without this information it can be generally concluded that the lateral placement in the most optimum location (based on geochemical, geomechanical logs, analyses, and a high value for GIP) probably contributed to the 1H-12 well’s better performance.

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Figure 18-Production Plot of the Newberry 1H-12 and five offset wells

Table 4-Frac Stages, Depths, Total Perforated Lateral Length

Drilling in the Eagle Ford Formation, South Texas, US We drilled a well that consisted of vertical, curve, and lateral sections exceeding 10,400-ft total footage in the Eagle

Ford formation. The curve section had an 8°/100-ft buildup rate (BUR), and the client needed to drill the build and turn profile while eliminating trips to change or adjust the bottomhole assembly. The client was also looking to minimize nonproductive time (NPT) and to stay within a 50-ft lateral window.

The section was drilled with the High-Build Rate Rotary Steerable System (RSS) and one of our special PDC bits.

This particular RSS allowed the client to drill out the 9 5/8-in. surface casing and subsequently drill from 2,631 to 13,188 ft in “one run” for a total footage of 10,462 ft. The High-Build Rate system was also used to drill the vertical section of the well and was able to KO (Kick Off) in the correct direction, building to 88! incline on an 8!/100-ft BUR. Once the curve was landed, the system drilled the entire lateral section. The bottomhole assembly maintained an average rate of penetration (ROP) of 90 ft/hr through the intermediate, curve, and lateral section. The sections were accurately drilled in six rig days, and the High-Build Rate system’s one-run performance was two days faster than the average for offset wells. With an average spread

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cost of $40,000 for this particular rig, the client saved approximately $80,000.00 in associated rig operating charges on this job.

Drilling in the Utica, Ohio, US We drilled a horizontal well with an 8°/100’ dogleg severity curve section with the High-Build Rate Rotary Steerable System. The client’s drilling plan included a hard line avoidance at total depth (TD), and the client wanted to significantly improve the rate of penetration (ROP).

The section was drilled with the High-Build Rate system along with one of our special 8 !-in PDC bits. The High-Build Rate Rotary Steerable System allowed the client to significantly reduce total days of drilling exposure; drilling the well in “one-run curve and lateral” on a three-dimensional profile - 2,159-ft curve and 7,462-ft lateral. The curve section was accurately landed in three rig days, which was three days ahead of plan. The well reached TD, 6.2 rig-days ahead of the 16-day performance target set by the operator based on previous area offsets. LWD High Resolution Resistivity Imaging Tool An operator needed to acquire high-resolution images to determine perforation placement for an unconventional well being fractured between two 600 ft offset wells. We used our high resolution resistivity imaging LWD service (Figure 19 shows the tool specifications) and helped optimize production by enabling the operator to see variations in the lateral section and adjust his production stages (Figure 20) to group rock with the same properties together and to isolate hazards. Figure 21 shows examples of various fractures and faults on the log display. The completion optimization plot shown in Figure 22 gives an overview of the wellbore trajectory along with the high-definition image log, and the fracture characterization for the eight frac stages included in this particular well. The high level of conductive fractures (blue bars in the stage interval track) indicates that this well was drilled too close to offset wells. To access more untreated rock, we recommended that a trajectory which placed the lateral deeper in the productive horizon would have been preferred. Based on the success of this operation, the operator decided to use the high resolution resistivity imaging service to place future unconventional wells and to optimize the completion and stimulation treatments. This method has been very effective, and can enable production from acreage that would otherwise have been abandoned. The imaging service has now been used in over 400 wells and has improved production by up to 20% (according to operators who use the service).

Figure 19–Tool Specifications

Figure 20–Typical Stage Adjustments. Figure 21–Fracture and Faults on Log Display

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Figure 22–Completion Optimization Plot – LWD Resistivity Imaging

Conclusions Three key points summarize the conclusions drawn by these authors for “Proper Placement of Wells and Hydraulic

Fracture Stages” in order to maximize the net value of the asset for the operator. 1. Begin With a Complete Understanding of the Reservoir 2. Use a Multidiscipline and Integrated Approach Across Each Phase of the Life Cycle 3. Effectively Use Modern Technology

Specific Conclusions • Downhole (wireline) geochemical (mineral spectroscopy), acoustic, and NMR tools can locate the most

fracable intervals, and also determine the location for placement of horizontal laterals. • High-Build Rate RSS and special PDC bits can achieve “one-run curve and lateral” wells. • Drilling Optimization increases drilling efficiency and reduces days on wells (cost). • Effective Well Placement maximizes reservoir exposure and locates the well in the sweet spots. • Maintaining Well bore quality reduces risk and Non Productive Time. • Arbitrary geometric method of placing frac stages along the horizontal laterals of shale wells and “copy-

paste” frac designs are still quite common. • The industry is building confidence in the optimizing a stimulation strategy, but it is still a challenging task. • In order to optimize a completion/stimulation strategy a multidisciplinary approach is required, including:

– Gathering and evaluation of geological, geomechanical, petrophysical, and geochemical data – Selection of the stage and cluster spacing based on the best reservoir properties, including natural

fractures, TOC, thickness, and mineralogy – Application of the optimum fluids, proppants and additives for the specific reservoir properties – Building a fracture design model with the objective of staying within the target zone while

maximizing the reservoir coverage – Integration of fracture model with geomechanical and reservoir models to evaluate the interference

of the hydraulic fractures for achieving the optimum production Good quality data is required to calibrate and evaluate the models. Due to extreme complexity of the nature of shale reservoirs, building “realistic” models is a goal that has not yet been attained.

• LWD high resolution resistivity imaging of horizontal laterals can result in increased well production. • The type of completion used directly affects efficiency during the fracturing process. • Each completion technique has its own benefits and considerations, dependent on application and the current

phase of the asset life cycle. Plug-and-Perf, during Appraisal phase, provides flexibility of stage placement, resulting in more time to gather data. Ball-activated systems provide efficiency during Development phase. Coiled tubing-activated systems offer accuracy and contingency options and can result in optimized fracs during the Development phase.

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Acknowledgements The authors would like to thank the management of Baker Hughes for allowing us to publish this paper. We would also like to thank and show our appreciation to the members of the BHI Unconventional Resources CORE (Center of Reservoir Excellence) team and the USA Land Geomarket team for their support and contribution to the contents of this paper. A special thanks goes to Matt Bratovich for his advice and input on petrophysics and formation evaluation. References Bhattacharya, S., and Nikolaou, M., 2011, Paper SPE 147622, Optimal Fracture Spacing and Stimulation Design for Horizontal Wells in Unconventional Gas Reservoirs, presented at the SPE Annual Technical Conference an Exhibition, Denver, Colorado, USA, 30 October – 2 November. Bazan, L.W., Lattibeaudiere, M.G., and Palisch, T.T., 2012, Hydraulic Fracture Design and Well Production Results In the Eagle Ford Shale: One Operator’s Perspective, Paper SPE 155779, presented at the Americas Unconventional Resource Conference, Pittsburgh, Pennsylvania, USA, 5-7 June. Brannon, H.D., Kendrick, D.E., Luckey, E., Stipetich, A., 2009, Multistage Fracturing of Horizontal Wells Using Ninety-Five Quality Foam Provides Improved Gas Production, Paper SPE 124767, presented at the 2009 SPE Regional Meeting, Charleston, West Virginia, USA, 23-25 September. Brannon, H.D. and Bell, C.E., 2011, Eliminating Slickwater Compromises for Improved Shale Stimulation, Paper SPE 147485, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, 30 October – 2 November. Cheng, Y., 2010, Impact of the Number of Perforation Clusters and Cluster Spacing on Production Performance of Horizontal Shale-Gas Wells, Paper SPE 138843, presented at the SPE Eastern Regional Meeting, Morgantown, West Virginia, USA, 12-14 October. Cramer, D.D., 2008, Stimulating Unconventional Reservoirs: Lessons Learned, Successful Practices, Areas for Improvement, Paper SPE 114172, presented at the 2008 SPE Unconventional Resources Conference, Keystone, Colorado, U.S.A., 10-12 February. EL Shaari, N., Minner, W.A., and LaFollette, R.F., 2011, Is there a “Silver Bullet Technique” For Stimulating California’s Monterey Shale?, Paper SPE 144526, presented at the SPE Western North America Meeting, Anchorage, Alaska, USA, 7-11 May. Franquet, J.A., Bratovich, M.W., and Glass, R.D., 2012, State-of-the-art Openhole Shale Gas Logging, Paper SPE 160862, presented at the SPE Saudi Arabia Section Technical Symposium and Exhibition, Al-Khobar, Saudi Arabia, 8-11 April. Jacobi, D., Breig, J., LeCompte, B., Kopal, M., Hursan, G., Mendez, F., Bliven, S. and Longo, J., 2009, Effective Geochemical and Geomechanical Characteristics of Shale Gas Reservoirs from the Wellbore Environment: Caney and Woodford Shale, Paper SPE 124231, presented at the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, 4-7 October. Jo, H., 2012, Optimizing Facture Spacing to Induce Complex Fractures in a Hydraulically Fractured Horizontal Wellbore, Paper, presented at the Americas Unconventional Resources Conference, Pittsburgh, Pennsylvania, USA, 5-12 June. Kennedy, R.L., Knecht, W.N., and Georgi, D.T., 2012, Comparisons and Contrasts of Shale Gas and Tight Gas Developments,

North American Experience and Trends, Paper SPE 160855, presented at the SPE Saudi Arabia Section Technical Symposium and Exhibition, Al-Khobar, Saudi Arabia, 8-11 April.

King, G.E., 2010, Thirty years of Gas Shale Fracturing: What Have We learned?, Paper SPE 133456, presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. King, G.E., 2012, Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor and Engineer Should Know About Estimating Frac Risk and Improving Frac Performance In Unconventional Gas and Oil Wells, Paper SPE 152596, presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 6-8 February.

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Meyer, B.R., and Bazan, L.W., 2011, A Discrete Fracture Network Model for Hydraulically Induced Fractures: Theory, Parametric, and Case Studies, Paper SPE 140514, presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 24-26 January. Mitra, A., Warington, D., and Sommer, A., 2010, Application of Lithofacies Models to Characterize Unconventional Shale Gas Reservoirs and Identify Optimal Completion Intervals, Paper SPE 132513, presented at the SPE Western Regional Meeting, Anaheim, California, USA, 27-29 May. Pemper, R., Han, X., Mendez, F., Jacobi, D., LeCompte, B., Bratovich, M., Feuerbacher, G., Bruner, M. and Bliven, S., 2009, The Direct Measurement of Carbon in Wells Containing Oil and Natural Gas Using Pulsed Neutron Mineralogy Tool, Paper SPE 124234, presented at 2009 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, 4- 7 October. Song, B., Economides, M. J., and Ehlig- Economides, C., 2011, Design of Multiple Transverse Fracture of Horizontal Wells In Shale Gas Reservoirs, Paper SPE 140555, presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 24-26 January. Vermylen, J.P., and Zoback, M.D., 2011, Hydraulic Fracturing, Microseismic Magnitudes, and Stress Evolution in the Barnett Shale, Texas, USA, Paper SPE 140507, presented at the SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, 24-26 January.