COST EFFECTIVE HORIZONTAL WELL TECHNOLOGY

Based on a workshop sponsored by PTTC's Central Gulf Region in Lafayette, Louisiana on May 12, 2005.

BOTTOM LINE

The workshop reviewed horizontal designs and application with a focus on "cost effective" design and application and experience/lessons learned. For horizontals multi-disciplinary asset teams are a must, as is the concept of designing the well "backward." Information on a multitude of design aspects/technologies provides a "big picture" laymen's viewpoint with a focus on common errors/failure modes and how to avoid problems. Management tools are provided, including a suite of challenges and checklists to the independent operator working with asset teams and service providers.

PROBLEM ADDRESSED

The need for increased unconventional natural gas production in the next 10 to 20 years has created a market, which independent operators in Kansas want to share in. However, information on the resources and techniques to evaluate them has been minimal. The Kansas Geological Survey has a responsibility to the people of Kansas to provide information on the development and economic production of resources vital to Kansas' economy.

KEY WORDS:

3-D Modeling and Well Planning, Directional Drilling, Guidance and Geo-Steering, Geology and Reservoir Engineering, Logging , Team Approach to Horizontals, The Three "Ws"

SPEAKERS:

R.G. "Bob" Knoll,
Maurer Technology, Inc.
 

TECHNOLOGY OVERVIEW

Horizontal well technology and application has grown dramatically over the last 10 to 15 years and in some settings it is now seen as the first choice. One example is the Western Canadian Basin. There an extremely varied industry in respect to both reservoir setting and resource type, with relatively thin, marginal mature fields, and a proactive supportive regulatory and fiscal regime led to their leading the world in diverse application of horizontal wells.

Lessons from Canadian experience include:

• The deeper the target reservoir, the less incrementally expensive a horizontal well is relative to a vertical well. The incremental cost of additional horizontal length within the reservoir is minimal to irrelevant.
• Although re-entries appear attractive on first look (no incremental environmental impact, no geologic risk, utilize the sunk cost of existing well), there are inherent downsides. Downsides include inherit all problems, limit choices of completions, limit other production and EOR techniques, and cost of well preparation can be prohibitive in shallow applications.
• It is accepted that a learning curve is required site-specifically. As local team expertise develops, well costs should be reduced and productivity ratios should increase. With maturity (statistics confirmed in several basins across the world), success rates above 70% should be anticipated and production vs. cost ratios exceeding a value of 2.0 (or more) are common.
• Industry has become very comfortable with open-hole completions.

In other areas where horizontal development has been less pronounced, key limitations have been found to be (1) lack of technical training and management exposure/comfort and (2) equipment supply limitations. Early "failures" with a much less than optimum design can discourage trying again and moving up the learning curve. Early on regulatory and fiscal regimes played a role, but are less inhibitory now.

When considering horizontal development, operators are encouraged to ask "why not?" vs. "why?" Candidates for horizontal wells are formations that have coning tendencies, unconsolidated zones or sand-producing tendencies, low pressure, low permeability, natural fractures, thin production intervals, compartments, viscous oil, or any combination of the above. The key strategy and "why" of a horizontal well is directly related to its profile. This profile will control all capabilities of well construction, completion and workover options. Profile can be utilized with completion refinement to control the production mechanism and maximize recovery. Many issues dictate the optimum profile design and numerous uncertainties affect the ability to generate the designed profile. Key uncertainties are geologic, survey, guidance capability and drive mechanism.

Practices Leading to Success
From studying successes and failures of horizontal wells globally, there are re-occurring basic concepts that lead to success or failure. Chief among those are an asset team having the appropriate disciplines effectively involved. Conceptually nearly everyone agrees with this concept, but in reality it is difficult to truly function as an interactive asset team.
Keys to an asset team performing are:

• Each member must have a working knowledge of their own and all other members' responsibilities, capabilities and limitations and appreciate the cause/effect interrelationships. This means cross-training is essential.
• The team leader must have an overall appreciation of the targeted technologies, must be able to distinguish between the different discipline's wants vs. needs, and balance the priority and value added of these competing needs.
• There must be a mechanism to efficiently document, capture and communicate the trade-offs made, implementation effects, and site-specific lessons learned.

Industry has painfully learned that there is no standard horizontal well application, design, or well construction program. Design must apply general concepts, arriving at a site-specific design for a given play/reservoir/lease and even down to the well level. In doing this, teams should resist pushing the envelope with overly complex designs or newest technology twists. Have relatively basic objectives for the first well and, through a progression of application, develop the site-specific design.

The “Three W” Design Criteria
The drilling function, or the "how" to drill the well, is typically the least problematic and should be the last element to be defined. First, the team must define:

• Where (geology, structure)
• Why (reservoir, drive mechanism, profile)
• What (production engineering, reservoir management, EOR, completion)

Having defined the above, then the team can develop the "how" (drilling, detailed well design, well construction contingencies, Go/No-Go decision points)

Geology and Reservoir Engineering
Developing a 3-D picture/model is essential for planning horizontal applications. As more horizontals have been drilled, industry has been surprised the degree of lateral variation that is evident. Fortunately new technical options are available to control the cost and time of developing a 3-D image. For the more basic settings, analytical models are often adequate for screening purposes. For more complex situations numerical simulation is required. Given the geological setting and production mechanism, modeling points toward what would be the optimum horizontal plan.

One key aspect of the geological model is vertical permeability relative to horizontal permeability. Sometimes one wants a flat, straight hole; in others such as reservoirs having flat impermeable shale barriers, a flat, straight hole would not be desirable.

With vertical wells a geologist's role has been primarily to evaluate "what has been drilled." With horizontals geologists become involved in actively steering the well to its desired profile, responding to data as drilling occurs. This requires an openness to rethink the geological model as data continually arrive.

Managing undulations (ups and downs in profiles) is part of the challenge. Excessive undulation causes excess friction, which may limit lateral length, and, since horizontals are extremely efficient horizontal separators, can cause pressure drop or multiple phase flow complications.

Directional Drilling, Guidance and Geo-Steering
Horizontals are based primarily on modern steerable motor capability. Drilling can occur in either the rotary or slide mode. When the bottom-hole assembly (BHA) is rotated by the drill string, the assembly will tend to drill in a straight line. Thus, corrections are made in the slide mode and straight-ahead drilling is conducted in the rotary mode. Three measurements (inclination, azimuth, and tool face orientation) are key to knowing where the well is (and where it is going). Dogleg severity is a key constraint of the profile. All potential downhole components must be checked for the maximum allowable dogleg severity. One should avoid the tendency to oversteer—the more corrections made, the more difficult it becomes to make corrections.

Measurement while drilling (MWD) systems include mud pulse telemetry. An alternative when multiphase fluids are used, which is often the case with underbalanced drilling, is electromagnetic pulse telemetry. With coil tubing drilling wireline telemetry is an option made viable by improvements in hardware/systems. Advancements are continuously being made to allow placing sensors closer to the bit, which is good but can be costly. Over-utilization of highly instrumented assemblies, which can be more prone to failure and are more costly (especially if lost downhole), is a common error in horizontals.

Geo-steering is much more than measuring a log response along the horizontal well length. It is a choice of numerous real time observations made while drilling, starting at the kickoff point. The curve shape, use of tangents and pilot holes are examples of geo-steering to help find the target. Observations can include mud logging, drilling parameters, inflow observations, etc. Since mud-logging operations are not dramatically altered in horizontal applications, mud logging is very cost effective with basic mud-gas monitoring being a direct indicator of drilled rock porosity and hydrocarbon saturation. Advanced gas traps and customized interpretive software have been developed. Sophisticated logging while drilling capabilities exist, but operators must beware considering them the answer. Critically evaluate whether they are needed, keeping in mind the "keep it simple" principle.

Evaluation and Production Logging
After drilling, conventional wire line-logging assemblies can be pushed (tools won't fall with hole angles above 60 degrees) into the lateral with pipe or tubing. Data is transmitted by conventional wire line. Wellbore imaging tools have become very popular, particularly in fracture identification, bedding orientation, etc. Note that it has been observed that both drilling induced and natural fractures are much more common than was thought based on vertical well evaluation.

Production logging tools are most often conveyed by coil tubing. Technology has advanced rapidly with larger tubes, improved modeling and quality assurance, etc. Fluid phase segregation, wellbore undulation, relatively low in-flow velocities, tool centralization, inflow fluxing and cross flow all dramatically complicate data interpretation. A common misinterpretation is that the majority of inflow is coming from the heel. Spinner and density logs that work well in vertical applications are only marginal in horizontals. Vendors are developing new "vane-type" tools designed to identify the degree of phase segregation, occurrence of phase override and other dynamics with multiphase fluids. For many reasons, segment testing, for which new tools are being introduced, is becoming accepted as the most reliable production logging method.

Completion Design
Completion design starts in the curved section of the well with respect to hole size and procedures employed to construct and case or isolate the non-productive curve. In general, it is recommended that the curve be drilled into the target and immediately cased in the first horizontal well in a field. Completion designs can range from open hole through to conventionally cased, cemented, perforated and gravel-packed. Outside of North America slotted-liner completions have been common, but they are losing favor because of inherent difficulty in defining the condition of free space behind the liner or the inability to impact this free space (i.e., water shutoff, stimulation). Globally industry is becoming more comfortable with the integrity and flexibility of open-hole completions.

Damage is a major failure mechanism in horizontals. Effective cutting removal is critical, particularly in finer/tighter applications. Pipe/fluid surging and ECD effects are amplified in horizontals. Drilling fluid damage is an obvious focus. There is no substitute for core tests to evaluate damage mechanisms and optimize drill-in and clean-up/stimulation fluids. Special steps and contingencies can be employed to minimize the perceived risk of coring in horizontal wells. Stiff coring assemblies must be short enough to make the curve.
 

CONNECTIONS:

R. G. "Bob" Knoll
Maurer Technology Inc.
28 Edcath Mews NW
Calgary, Alberta, Canada T3A3S7
Phone: 403-239-4168
E-mail: bobknoll@shaw.ca

For information on PTTC’s Central Gulf Region and its activities contact:

Mr. Robert H. Baumann, Managing Director
Center for Energy Studies, Louisiana State University
Energy, Coast and Environment Building
Nicholson Drive Extension
Baton Rouge, Louisiana 70803
Phone 225-578-4400 Fax 225-388-4541
E-Mail rbaumann@lsu.edu

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

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