joint industry project [jip] proposal best practices in ......the process involves the high-pressure...

$: Joint Industry Project [JIP] Proposal Best Practices in ......The process involves the high-pressure injection of 'frac fluid' into a wellbore to create cracks in the deep-rock formations$
Endeavor Management

950 Echo Lane P + 713.877.8130

Suite 200 F + 281.598.8895

Houston, Texas 77024 www.endeavormgmt.com

Joint Industry Project [JIP] Proposal Best Practices in Unconventional

Completion Operations

Submitted by Endeavor Management Aug 10, 2017

http://www.endeavormgmt.com/

JIP Proposal for Best Practices in Unconventional Completion Operations

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© 2017 Endeavor Management. All Rights Reserved.

Proprietary and Confidential Material

The ideas, pricing, and terms of this proposal are the property of Endeavor Management. We respectfully request that the information not be disclosed or distributed to anyone outside the requesting companies or their parent companies, without the express written permission of Endeavor Management.

Background Hydraulic fracturing is a well stimulation technique in which rock is fractured by a pressurized liquid. The process involves the high-pressure injection of 'frac fluid' into a wellbore to create cracks in the deep-rock formations through which natural gas, oil, and water will flow more freely. When the hydraulic pressure is removed from the well the injected proppant (small grains of sand and/or aluminum oxide) holds the fractures open.

Hydraulic fracturing began as an experiment in 1947, and the first commercially successful application followed in 1950. Millions of "frac jobs" have been performed worldwide on oil and gas wells with most of those within the U.S. Such treatment is generally necessary to achieve commercial flow rates in shales and tight reservoirs.

The profitability of oil and natural gas development activity depends on both the prices realized by operators and the cost and productivity of newly developed wells. Prices, costs, and new well productivity have all experienced significant changes over the past decade. Price developments are readily observable in markets for oil and natural gas, while trends in well productivity are tracked by many sources, including EIA's Drilling Productivity Report which focuses on well productivity in key shale and tight oil plays.

Regarding well development costs, there is a general understanding that they are sensitive to increased efficiency in drilling and completion, which tends to lower costs. Shifts towards longer laterals, frac intensity and more complex completions tend to increase costs. Great strides have been taken in drilling efficiencies; two or three wells are now being drilled in the time that it used to take to drill one. In contrast, well completion costs are increasing in real terms due to changes in completion complexity. Overall cost trends are generally less transparent than price and productivity trends. Given the role of present and future cost trends to determining future trajectories of U.S. oil and natural gas production under a range of possible future price scenarios, it is clearly important to develop a deeper understanding of cost drivers, operational best practices and the future trends in both of these areas.

https://en.wikipedia.org/wiki/Well-stimulation

https://en.wikipedia.org/wiki/Wellbore

https://en.wikipedia.org/wiki/Natural_gas

https://en.wikipedia.org/wiki/Brine

https://en.wikipedia.org/wiki/Hydraulic_pressure

https://en.wikipedia.org/wiki/Aluminium_oxide

https://en.wikipedia.org/wiki/Shale_gas

http://www.eia.gov/petroleum/drilling/



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Situation

There is no better time than the present for the pursuit of solutions to the most pressing issues facing operators around unconventional completion operations. These issues are difficult but solvable. In this “lower for longer” cost environment, assuring that every operator has access to the best practices to drill and complete their wells is critical to continuing economic viability. From our perspective, the industry has a widely divergent set of capabilities and opinions in how best to execute completion operations. Some operational practices are much more efficient (from both a cost and outcome basis) than others and thus the need for a benchmarking effort which the industry can use to start to move toward even more efficient completions operations.

The Issues

Each one of the issues receives further discussion within the appendices.

1) Planning for Simultaneous Operations / Site Preparation a. Logistics b. Pressure control c. Inventory management d. Supply chain coordination e. SIMOPS Planning – Completion technique, multi-well ops, redundancies, etc.

2) Multi-stage Frac'ing - Surface Equipment / Operations a. Project team coordination b. Equipment selection, operations and down-time c. Safety and risk management d. Supply chain and scaling logistics e. Environmental issues – weather, regulations, etc.



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3) Multi-stage Frac'ing - Subsurface Equipment / Operations

a. Completion technique selection b. Engineered or geometric c. PnP, sleeves, pinpoint, other d. Reservoir data collection – Logs, DFITs, Pressure/Temperature, etc. e. Well interference / Frac propagation control f. Equipment selection, operations and down-time

4) Post Frac Wellbore Cleanout a. Project team coordination b. Equipment selection, operations and down-time - Rig, CTU, BHA c. Fluids management d. Sand control

5) Flowback Operations and Water Handling a. Project team coordination b. Data collection – Reservoir, frac design, production, etc. c. Equipment selection, operations and down-time d. Safety and risk management e. Environmental issues f. Flaring g. Fluids management h. Sand control

6) Economic Model a. Probabilistic economic model evaluating various scenarios using Monte Carlo

analysis b. Potential value of best practices in specific circumstances c. Sensitivity analysis to understand potential outcomes d. Model can be used after JIP to aid in decision making



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Project Objectives

Endeavor Management proposes to provide leadership in identifying and developing key principles to drive efficiency and optimize costs within each of these operational areas. We will serve as a focal point in coordinating input from the subject matter experts and facilitating group discussions to prioritize input and conclusions. The goal of this JIP is to develop recommendations showing cost trade‐offs for best practices in completion operations, to help operators and service companies identify the most efficient and safe ways to complete unconventional wells. Where significant operational or technical hurdles are identified the JIP will highlight potential new solutions, including identification of service providers and manufacturers who can supply these new innovations.

Stage 1 Best Practice Definition

Proceed with Best Practice definition as follows:

1) The Member Companies (MCs) will be asked to nominate Subject Matter Experts (SMEs) to assist in the technical definition and provide input, comments and guidance as the teams move toward definition of best practices and solutions to the defined issues. These SMEs will serve as technical representatives for the MCs. It is not mandatory for a Member Company to have SMEs but it would be beneficial. One or two face-to-face meetings per month for a three month period are expected to develop a common understanding of the issues and potential solutions. (From this point forward in this Proposal, when “Member Companies” are mentioned it is presumed that the Member Companies may include their own SMEs in the transactions of the Project – or not include ‐ as they see fit.)

2) Endeavor will generate documentation in which potential operational best practices are identified and evaluated within each of the areas listed above. Pros and cons will be analyzed by the Member Companies to specify their effect on operations, schedule, economics, safety, and other areas of interest.

3) A consolidated summary will then be sent to the JIP Member Companies in draft form for evaluation, review, and comment.

4) Endeavor will review this information with the Member Companies in a Technical Kickoff Meeting and solicit comments. The best practices identified in these meetings will then be used in Stage 2. It is planned that these meetings will be organized on an Issue‐by‐Issue basis, travel and logistics permitting.

5) Best Practices and Issues defined in the Stage 1 Kickoff meeting will be prioritized and a plan will be developed to define tasks for more detailed economic evaluation.

Stage 2 Finding Solution Concepts

1) Endeavor will seek possible solutions from within the JIP Member Companies and their SMEs, from service providers and from within Endeavor’s skilled team.



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2) When all Issues have been documented, Endeavor will meet with the JIP Member Companies collectively for open discussion regarding these Issues. It is planned that this set of meetings be handled on an Issue‐by‐Issue basis similar to the Kickoff Meetings.

Deliverables

1) Results Review/Final Review: Report 2) The results of Stages 1 and 2 will be revised to reflect the comments and discussion

obtained via the review meetings. The findings will be documented to the JIP Member Companies. Each Issue summary will include recommendations for follow‐on evaluation after this JIP, as appropriate.

3) Publish the report to all JIP Member Companies, along with a summary presentation. 4) In order to stimulate industry involvement in solving these Issues, Endeavor will present

a summary of the findings at appropriate conferences and industry gatherings and publish in industry publications.



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Assumptions and Constraints

Endeavor Management will provide professionals with appropriate backgrounds to facilitate and participate in the reporting and review process and share their knowledge and experience. The JIP Member Companies will share sufficient information about their technical requirements, operational experience to date, future needs, service company offerings and related information so that the Endeavor advisors can develop informed assessments of the current status of the industry and most likely solutions for each Issue. Endeavor will establish guidelines with the Member Companies to outline when and how the information within the scope of this study will be discussed or disclosed (a) between JIP Member Companies, and (b) to any party outside the JIP Member Companies.

Professional Fees and Expenses

This work will be performed on a lump sum basis. Endeavor has allocated a fixed number of man-hours for each Issue and will adjust the hours between Issues if one area needs less work and another needs more work during this JIP effort. It is presumed that the Member Companies will each nominate a single‐point contact to monitor progress and to coordinate with its SMEs. Endeavor proposes to report progress on a “by Stage” basis.

Each JIP Member Company will be billed half of their total amount at project kick‐off and the other half after the draft Final Report is issued. All invoices are due in 30 days. The cost per participant is expected to be $ 60,000 based on 10-12 participants. This includes expenses such as travel to Houston for meetings for Endeavor personnel who live out of the Houston area.

The Member Companies will be notified in advance if the project requires additional hours due to significant changes in project scope, etc. Additional work would only occur if approved by unanimous approval of the JIP Member Companies.

The above proposed price of $ 60,000 per Member Company includes:

Stage 1

Summary defining each of the identified Issues confronting unconventional completion operations, in draft form for review by the Member Companies.

1) Review and comment in an open discussion for each of these Issues in a meeting format. In the spirit of a Joint Industry Project, Endeavor recommends a common meeting for each Issue. These may be combined on related Issues.

2) Endeavor will follow‐up on specific possible solutions identified in the Stage 1 meetings to gather more information.



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Stage 2

Report outlining – for each of the Issues. 1) Review and comment in an open discussion for each of these proposed solutions in a

meeting format for each Issue. These may be combined on related Issues. 2) Completion of the overall report by the addition of Stage 2 information/solutions to the

initial information gathered in Stage 1. 3) Preparation of a report summary in PowerPoint format for use as follows:

o One E‐copy to each Member Company for internal use. o Presentation of the report summary at appropriate shows, conventions,

conferences, and industry publications by Endeavor and/or the JIP Member Companies.

Time Frame

Endeavor proposes to start the work as soon as JIP Member Company participation is confirmed. Stage 1 will be ready for review in approximately 6 weeks after award date, subject to completing the meetings with partners. Stage 2 will be ready for review approximately 8 weeks after the last Stage 1 review meeting is completed. The Stage 3 final report will be delivered 4 weeks after final comments are received from Stage 2.



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Contact

Should you have any questions or need additional information regarding this proposal, please contact either:

Project Manager, David Gray at 713-240-9931 at [email protected] Engagement Sponsor, Michael Shook at 713‐829-0437 or [email protected]

We look forward to working with you on this project. Please sign below to show acceptance of this proposal.

Sincerely,

David A. Gray Director – Technology Commercialization Endeavor Management

mailto:[email protected]

mailto:[email protected]



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APPENDIX A

Issue 1: Planning for Simultaneous Operations / Site Preparation

Concise Summary of Issues to be Addressed

This study will establish best practices relative to site preparation, rigging up temporary equipment and optimizing the overall site location layout. It will also examine alternative options for simultaneous operations.

Background and Overall Methodology

Rigging up temporary equipment (frac stacks, zipper manifolds, pressure pumping equipment, water tanks, sand storage tanks, coiled tubing equipment, workover rigs, wireline equipment, and pump down equipment) has become standard procedure during the completion process. The set-up, layout and coordination of this equipment on location is a critical path item which drives efficiency, speed and safety during the completion process. Additionally, many of these activities may occur simultaneously.

Areas of focus for site Prep:

1) What are best practices for frac tree configuration? Consider the impact of: o Valve orientation o Frac stack orientation - Goat head location, UMV, LMV, etc. o Pump down equipment rig up o Flowback equipment rig up o Use of frac stands, cranes or man lifts

2) What impact can pressure testing off site have on overall cost on location and costs? 3) What are best practices for offline activities that can be done while the drilling rig is on

location? Consider: o Logging o Tubing heading o LMV install o Casing testing o Tractor perforations o Open sleeve o Infectivity rate

4) What are the best practices for multi well frac? Consider: o Zipper manifold o Snorkel o Single well rig up o Pre-rigging and testing missile prior to pumps arriving on location

5) What are the considerations for selecting Monoline or multi line for frac treating? 6) What are best practices to minimize transition time? Consider the impact of:



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o Simultaneous operations o Multi WL units o Greasing manifolds for simop greasing o Isolation on multiwell pads (splitter between zippers)

7) How can efficiencies be improved on small location / footprint? 8) What is the cost/benefit ratio of electric versus hydraulic valve actuation? 9) What efficiencies are gained by utilizing the factory model? Consider:

o Same people / same job o Same size trees and orientation o Same pad layout

Deliverables

Report that establishes best practices for optimizing site preparation and equipment rig up and layout. Suggestions for tracking metrics will be included where possible.



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APPENDIX B

Issue 2: Surface Equipment / Operations


This initiative seeks to identify areas in frac operations where significant efficiency losses can be incurred if issues arise, and the best practices that can be used to mitigate that risk.

Background

In recent years the frac factory approach has created dynamic logistical requirements while seeking to maximize the speed and amount of frac work done. The efficiency of each step in the frac completion is influenced by many processes; if any process lacks optimal efficiency, an improvement opportunity exists. Addressing these opportunities benefits the objective of executing a high-quality frac completion at highest speed and lowest cost. New technologies that are now coming available will also be highlighted.

Discussion

Hydraulic fracturing originates in a complex combination of equipment, people, fluids, chemistry, and proppants. Achieving high efficiency in frac operations requires logistical excellence and avoidance of down time in order to avoid significant incremental costs. Embedding proven quality practices results in highest efficiency at the lowest system cost.

Some of the areas of focus are:

1) What is the interface between the various well site services – how is a project team atmosphere created and who acts as the project manager?

2) What are best practices in the selection of frac equipment? 3) What are the logistical issues around treating lines and how are efficiencies impacted by

rate and pressure? 4) What are best practices for monitoring and minimizing risks associated with erosion? 5) Which equipment types are most susceptible to failure and what are best practices to

minimize the down time associated with them? 6) What are best practices to address coming EPA rules on sand / proppant dust mitigation? 7) What are best practices for scaling logistics as intensity and size of frac jobs increase? 8) What are best practices for dealing with complexities created by water recycling? 9) What are best practices to mitigate the negative impact of extreme heat and cold weather

conditions on completion operations? 10) What are the best practices for use of coordinated / simultaneous operations, taking into

account safety, cost, and efficiency?



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Deliverables

A report that suggests best practices for frac operational areas that carry significant risk to overall completion efficiency, by geographic area where applicable. Suggestions for tracking metrics will be included where possible.



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APPENDIX C

Issue 3: Subsurface Equipment / Operations

Concise Summary of Issues to be Addressed This report will discuss the many options, efficiencies, and contingencies that will help the operator to choose the most cost effective means for their installation.

Background

Cemented liners stimulated with the process called “plug-and-perf” is the predominate type of completion currently in the US. The other types of completions methods have their place and appropriate fields where they are very successful. This document will address the options, rig up, installation, activation, contingencies, and rig down of the different types of completions.

The completion is the part of the well that provides access to the formation and a path way for the stimulation and the production. There are many different types of completions used in the shale plays. This report will focus on the most dominate types. One is “plug-and-perf”. It is the process of installing a frac plug, perforating, stimulating, and then repeating the same scenario for every stage in a cemented liner. Open hole completions is another, this process consist of installing a liner with packers and sleeves into the open hole. Coiled tubing and cemented sliding sleeves round out the most popular types of completions used in the shale fields. All of these completion options have multiple variables making endless possibilities. New technologies that are now coming available will also be highlighted.

Discussion

Each question below will all be dependent on the customer’s requirements. There is no one right answer for everyone.

Cemented Liner

1) Best practice for installing the cemented liner. 2) Most efficient way to test the liner based on individual requirements. 3) What is the best way to establish flow rate for first stage after cementing in your field?

o Toe subs, o wet shoes, o TCPS

4) What isolation method between stages is most effective for your specifications? o Frac Plugs o Sleeves

5) What is the best way to maximize run in speed with wireline? 6) What is the best practice for removing Frac plugs?

o Milling



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o Dissolving 7) What is the best practice for removing balls in the cemented sleeves?

o Milling o Dissolving

8) What is the best practice for contacting the formation? o Perf charges o Sleeves o Jetting

9) What is the most cost effective way to rig up and rig down?

Open hole

1) Best practice for installing an open hole liner. 2) What is the best practice for isolating the liner against the formation?

o Mechanical packers o Swell packers

3) What is the best practice for individual stages isolation? o Sleeves o Plugs

4) What is the best practice for contacting the formation? o Perf charges o Sleeves

5) What is the most efficient means of injecting Balls in the liner? 6) What is the most efficient means of removing the isolation means in the liner?

o Mill o Dissolve o Neither

7) What is the most cost effective way to rig up and rig down?

Deliverables

A report that suggest the best practices and options for completing a shale well along with contingency options, providing a best practices economic model and/or decision tree for cemented or open hole liners.



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APPENDIX D

Issue 4: Post Frac Wellbore Cleanout


Background

Milling of temporary plugs during the completions process has become standard procedure in the majority of “plug-and-perf” operations. The primary purpose of milling is to remove the temporary isolation device (e.g. bridge plugs, frac sleeve), which are used to separate each individual zone in the well lateral which is being stimulated. Milling operations are typically accomplished utilizing coiled tubing, workover rigs and/or snubbing units. Selection of the milling mechanism, technique and operational technique are all critical considerations during the milling process. Speed, safety and efficiency are also key considerations.

Discussion

This study will assess efficiencies for milling plugs, as well as examine alternative options and various types of equipment.

Milling focus areas:

1) Who should assume the lead in the milling process? What are the best practices for assuming operational leadership in the milling processes on location?

2) What are the considerations for selection of the milling mechanism (e.g. coiled tubing, workover rig, snubbing unit, combination thereof)? o What is the best practice for selection of coiled tubing unit size taking into account

annular velocity, risk of completing the operation, drilling efficiency and overall cost?

o What is the best practice for selection of workover rigs taking into account drilling efficiency, safety, required pressure control equipment and overall cost?

3) What criteria should be considered in selecting a Bottom Hole Assembly for different types of temporary plugs? o How do you determine weight-on-bit? How important is this information? o What is the optimum milling speed/penetration rate?

4) How long should it take to mill a plug? 5) At what point in your overall completion process should you rig up/rig down your milling

equipment? 6) How do you monitor fluid returns? 7) What are the best practices for re-using milling fluids? 8) What chemicals (surfactants, bactericides, and friction reducers) should be considered for

use in the milling fluids? 9) What AV’s are needed for optimal clean out? Does rotating pipe accelerate well cleaning?



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10) What are the advantages and disadvantages of balanced, over-balanced and under- balanced milling?

11) What is the process for minimizing the number and type of short trips? 12) What other operating procedures can be utilized to promote milling efficiency (e.g. using

production tubing to mill and drop the bit off after last plug)?

Deliverables

A report that suggests best practices for frac operational areas that carry significant risk to overall completion efficiency. Suggestions for tracking metrics will be included where possible.



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APPENDIX E

Issue 5: Flowback Operations and Water Handling


Background

The flowback process is used primarily while drilling out plugs (composite or sand) and after the stimulation treatment performed on the well. The intent is to flow back four phase fluids under varying pressures in a controlled environment. During the process, portable, fit-for-purpose equipment is rigged up to connect the frac stack/well head to flow through a series of chokes, manifolds, separation systems and containment systems. There are several different configurations that we will discuss but the primary components of the flowback process generally consists of flow iron, plug catcher, choke manifold and a sand trap/4 phase separator for solids control. Flowing back the abrasives fluids and solids utilizing the flowback temporary set up will minimize erosion of production equipment and flowlines. It can also provide real time data and performance of the well after the stimulation treatment. This data can be utilized for reservoir analyses, frac design or for the sizing of production equipment.

Discussion

Is flowback the best way to clean the well bore to maximize production flow rates after the stimulation treatment? Historically, this has been done with surface equipment and extended flow periods. This study will assess efficiencies of various flowback operations as well as examine alternative options.

Flowback Focus Areas

1) Areas of focus will include: o How long should you flow the well? What is the optimum flow period? o What flow measurement criteria are important? o How does BS&W effect decisions? o What is the optimum design or layout of equipment? o How do you select flow line size and to optimize velocity while minimizing erosion? o What choke sizes should be used to minimize pressure drops and erosion?

2) How do you maximize efficiency in: o Rig up / rig down operations o Offline operations (SIMOPS) o Extended CT clean out (sweeps and AV’s) o Flowing the well to existing production

3) Other areas to be addressed include: o How do you measure or define success during the flowback period? o What are the differences between flowback and well testing process?



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o How do you minimize erosion? o What are the challenges of flaring gas? o What are the best practices for flowing wells back in Casing and in Tubing?

Deliverables

A report that suggests best practices for frac operational areas that carry significant risk to overall completion efficiency. Suggestions for tracking metrics will be included where possible.

1) Flowback criteria (length of flow, rate, draw down, BBL recovered, etc.) 2) Type of equipment 3) Flare / production 4) Water haul / reuse water 5) Casing flow / tubing flow 6) Things you can do to prep the well for pumping unit / artificial lift



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APPENDIX F

Issue 6: Economic Modeling and Impact of Benchmarking


Background

The upstream industry in the Americas has undergone a significant transformation during the last four years, this requires a holistic understanding of project valuation and execution as continuing and new operations are considered. Costs, Competencies, Technologies, Markets.

It is certain that a significant effort in the shale field development segment is focused into “factory drilling”, while factories in other industries focus on keeping the manufacturing environment as stable as reasonably possible to maximize throughput efficiency, it is clear that the environment in unconventional operations will remain in flux for the foreseeable future.

These recent changes require that new operational options, potential significant changes and technological frontiers are evaluated comprehensively. This part of the JIP will attempt to model these aspects.

Discussion

Modeling of Proposed Scenarios for Decision Making

Economics Modeling

1) Changes in the economic modeling given the new industry (operational options, supply-demand, pricing, technology)

2) Decision making impact of new economic parameters (price, market, supply chains) 3) Expectations on operations risk management, identification of new risks with this industry

shift in personnel/pricing/technology. 4) Modeling of decision making and evaluation of alternatives using Monte Carlo analysis

Deliverables

1) A report that suggests best practices for frac operational areas that carry significant risk to overall completion efficiency, by geographic area where applicable.

2) Suggestions for tracking metrics will be included where possible. 3) An excel file with the simulation information and Monte Carlo analysis results



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Example results panel shown below.

Results panel will allow the client to evaluate various technical options and the financial impact, at the same time understand an analysis of scenarios and probability distribution based on critical system inputs. The model will be provided in a “user-friendly” form so that participants can continue to use after the JIP.



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APPENDIX G

Biographies – Endeavor Management Project Staff

Engagement Sponsor: Michael Shook

Executive Vice President – Oil and Gas Practice

Michael Shook is an experienced Executive Coach, Leadership Development expert, Team Facilitator, Change Management Consultant, and Business Strategy Consultant. Before joining Endeavor, Michael worked for 20 years at Shell Oil in various Exploration and Production positions. His experience includes developing and implementing business strategies, negotiating and implementing mergers and acquisitions, and leading new technology commercialization. He has worked in leadership and strategy development, coaching and alliance creation with many oil and gas operators and major service companies. Michael holds a Master’s Degree in Business Administration from the University of Houston, where he graduated with Honors and second in class standing. Michael also holds a BBA in Management from Texas Tech University. Michael is a certified Executive Coach, and certified in the Birkman Assessment, 360 performance feedback, change management and team leadership.

Project Manager: David A. Gray

Director – Technology Commercialization

David Gray has over 35 years in upstream oil & gas. He has deep operational experience with

over 20 years in executive management roles with oilfield service organizations – both large

integrated companies and smaller, high-growth companies. He has field and management

experience in North America, Middle East and Asia; his technical expertise spans the oilfield life-

cycle – formation evaluation, drilling, completions, production and intervention. David held

global leadership positions in operations, business development, strategic marketing and new

product development. For the past several years David has focused his energy on

unconventional resources through implementation of innovative processes and value-adding

technology. David participated in and led many strategic initiatives as an internal “change-

agent” and as an external consultant. He was instrumental is driving measurable improvement

in the following areas: field operations management best practices, global strategic planning,

new product development & commercialization, post-acquisition organization integration,

strategic account management, salesforce effectiveness, and strategic pricing. David holds an

MBA from the University of Texas and a BS Civil Engineering from the University of Alabama.

David has served as president of the Houston chapter of the Product Development &

Management Association, is certified NPDP and has been a featured speaker on portfolio

management and team dynamics.



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Team Leader: Douglas A. Scott

Doug Scott is the current President of DMS Solutions, a completions consulting company. He has over 28 years in the oil and gas industry and has served in a variety of roles in both the North American and International markets. His primary areas of focus include management of upstream oilfield service companies, driving growth in oilfield service operations both organically and through acquisitions and working with major oil and gas operators to improve their overall completions efficiency through the deployment of the factory model in shale operations. Doug previously served as Executive Vice President of Weir Group's Pressure Control Division, a global provider of wellhead and flow control equipment until April of 2014. He worked with Weatherford International as Director of Pressure Control Operations in the Western Hemisphere from March 2007 until May 2012. Prior to Weatherford, Doug worked with Expro as their North American Operations Manager focusing on subsea test trees and their completion offerings. In the early portion of his career, Doug served at the leadership level for multiple other completions based companies and been involved in start-up operations in Alaska and expansion into West Africa.

Team Leader – Ron Hersche Ron Hersche is the current VP of QHSE for Weir Pressure Control. Ron has more than 30 years of industry experience gained through domestic and international positions. In his 30+ years he has worked from the field technician to District / Country/ Global responsibilities. Experiences range from managing the growth and efficiencies of products to businesses. These associated businesses and products ranged through Drilling, Completions and Production phases of our industry. Early in Ron’s career he worked in the Production Fields for Dome Petroleum then moving into well testing for Northland Production Testing. Northland was one of the early service providers of Under Balanced Drilling, who eventually won a contract in the North Sea for UBD. Ron then went on, after acquisition to work for Precision Drilling who bought Northland for their UBD expertise. After 2005 he took on more of a Quality role and training role for UBD and Well Testing operations until 2012 at which time he joined Weir as their Director of Quality operations. From 2014 to present he took on his current role of VP-QHSE for Weir Pressure Control.

Team Leader: Patrick L. Walker Patrick L. Walker has over 25 years of experience in the Hydraulic Fracturing, Chemical Stimulation, and Formation Evaluation segments of the energy services industry. He has held a variety of technical roles including research and development, sales, training, senior advisor, and engineering management. He specializes in the optimization of fracturing completions, mentoring technical staff, and advanced 3-D fracture design and analysis. He has over 10 years of experience working directly with clients in unconventional resource plays across the US. Most recently, Patrick served as the Deployed Technology Manager for Trican’s US region. In this role he was responsible for the region’s engineering staff for Coiled Tubing, Cementing, Fracturing, and Nitrogen service lines. Responsibilities also included advanced fracturing design projects, guiding research projects to meet customer needs, and bringing new technologies to successful



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implementation in the field. Prior to Trican, Patrick was the senior US fracturing advisor at Weatherford. Duties included advanced fracturing design projects, working directly with Completions teams in client’s offices, training staff in formation evaluation and 3-D fracture design, and developing new product and processes to optimize unconventional well performance. Patrick received his Bachelor of Science in Chemical Engineering from the University of Arkansas at Fayetteville.

Team Leader: Ted Zaleski Ted Zaleski has over 32 years of oilfield service company and E&P experience. He has extensive knowledge and experience in drilling and his previous tenure with Baker Hughes, Inc. includes Vice President of Engineering for Hughes Christensen and Vice President of R&D for Hughes Tool Company. He has traveled extensively and made customer contacts in most oil producing areas around the world. Team Leader: John M. Jameson John M. Jameson is an independent consultant with over 30 years in the oil and gas industry serving in a variety of roles including strategic planning, mergers and acquisitions, consolidation and integration of multiple businesses and operations management. He has spent the majority of his career in senior leadership positions in the upstream and midstream oilfield service sector. He is currently serving on the Board of Liberty Lift Solutions, LLC, a privately held provider of Artificial Lift Solutions and CAM Integrated Solutions, a privately held provider of Midstream Engineering Solutions. John served as President of Weir Group's Pressure Control Division, a global provider of wellhead and flow control equipment until December 2013. He worked from June 2010 until March 2012 as President and Chief Executive Officer of Universal Pegasus International, a global provider of engineering design, project management and field services for the energy industry. Prior to Universal Pegasus, John worked with Weatherford International for twelve years in a variety of leadership roles including Vice President of Operations in Canada and Senior Vice President of Operations in the U.S. He has also been involved in the growth and integration of Weatherford's Completion and Production Systems groups throughout the world as well as organizing and driving the start-up and growth of Weatherford's $1 billion annual revenue Pressure Pumping Group. Prior to his career at Weatherford, John worked with Halliburton Energy Services for 16 years, where he served in various leadership roles including Business Unit Manager, Integrated Solutions Business Unit Manager for the Eastern Hemisphere, and Global Marketing Manager for their Fracturing Services Group. John received his BS in Mechanical Engineering from Georgia Tech in Atlanta, Georgia and his Master’s degree in Business Administration from Centenary College in Shreveport, Louisiana.



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Team Leader: Jerry Lieberman Director – Decision Analysis Jerry Lieberman has assisted clients for more than 15 years making major strategic decisions and planning their implementation. Working in diverse industries, including oil and gas, IT, manufacturing, and automotive, Jerry has helped leadership teams develop and implement high-value strategies for cost reduction, new work processes, technology selection, IT services, new product development, and new business models. This includes managing the project team, maintaining relationships and clear communications with senior level management and stakeholders, providing planning and strategic guidance for strategy value realization, and integrating the value story with needed actions for implementation. Jerry was a Principal at Decision Strategies and held various director level marketing and planning positions at General Motors. Jerry holds a Ph.D. in Mathematics from The University of Rochester.

joint industry project [jip] proposal best practices in ......the process involves the high-pressure...

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