Buzz Words in the Upstream – March 1998

The upstream side of the oil and gas industry has witnessed unprecedented technical advancement over the last 10 to 15 years.  As an example, the horizontal, extended reach, and underbalanced drilling capabilities existing today were simply unheard of in the early ’80s.  These technologies have, at times, demonstrated tremendous benefit, and these terms are amongst the key “buzz” words in modern exploitation terminology.  However, there have been many economic failures where these technologies have been inappropriately, or inadequately applied.  The author has been exposed to numerous and varied horizontal well applications globally over the last 15 years.  Extensive post-audit of this field experience has revealed that there exist some general failure reasons which are continuously repeated.  A few of these universal failure themes may be  identified, and thus avoided, by examining the myths & misconceptions surrounding the more popular buzz words.

When walking through the hallways of technical events (forums, conferences, schools, etc.), one can hear key words repeated from group to group.  Based upon the  frequency of use over the last decade, it must be accepted that horizontal wells have had the single most important impact on the way we exploit our reserves.

The curve presented in Figure 1 demonstrates the dramatic “value-added” capability of a properly conceived, designed, and implemented horizontal well re-completion program.  This Mid-West U.S. vertical well water-flood was at the end of its economic life.  The field represented a significant liability of well abandonment and reclamation.  The reverse of decline and delivery of incremental reserves resultant from the horizontal well re-completion program has salvaged the asset and generated significant additional cash-flow (Ref. #1).  Does this experience imply that all mature fields have a chance for a second life cycle?  What is the true success rate of horizontal technology applications?

A recent article (Ref. #2) on the success rate of horizontal wells indicated that overall technical success was reported (via survey of operators in the U.S.) at 95%.  Yet the corresponding economic success of the same activity was only 54%.  It would appear that nearly half of these technical successes were unprofitable.  In order to investigate the cause of this range of economic results, we first must agree on what horizontal well technology encompasses.

HORIZONTAL WELL —  When asked, most oil field professionals will suggest that a horizontal well is defined via some reference to hole inclination similar to the formal definition offered by the API (Ref #3).  This is the common response to the query, and reflects the prevailing attitude of the industry in general.  That is, “a horizontal well is a more advanced method of directional drilling”.   This represents a serious, yet common, misconception.  When less experienced operators  first consider  horizontal wells , the first issue they typically think about is the drilling function (i.e., “how” are we going to do this.)

Historically, the drilling function has been treated as a service, or “means to an end”.  When asked to define their basic function, the Drilling Managers would say they were paid to drill vertical development wells safely and cheaply.  If the well reached prognosed TD within budget, the drilling operation had achieved the goal, a technical success. It was not a drilling function failure if the reservoir was not there, or of uneconomic inflow capability.

In horizontal technology application, the drilling function is dramatically  expanded.  How the well is drilled, the curve definition, well shape, direction, geo-steering turn limits, completion type, etc., all have substantial, if not dominant impact on both the initial productivity of the well, and all long term strategic options for the well.  Failure to recognize this subtle, yet critical difference in drilling function is a common  mode of failure.  Applying horizontal wells is not simply an altered drilling process, it is a fundamental change in exploitation methodology.

An alternate definition has emerged which may be expressed as a horizontal well is an enhanced oil recovery (EOR) process.  This definition is more appropriate since it relates to the exploitation benefit potential of horizontal wells.  How is it that the type (or shape) of a well can define the production process?  In basic terms, a horizontal pipe-line shape has two inherent advantages over the point-source penetration of a vertical well:

1^st Dramatically increased and optimally oriented access to the “sweet-spots” of the reservoir.

2^nd More efficient immediate, and long-term use of the reservoir, and/or injection pressure distribution within the reservoir/well system.

These benefits will apply (to some degree) to all reservoirs.  The key is — will the site-specific reservoir setting gain sufficient benefit to justify the increased cost, technical challenge, etc.  This will commonly lead the uninitiated operator to ask “where” should we apply this technology.  But this approach also has pitfalls.  The response of less aggressive operators when challenged on their utilization of this technology is typified by, “We are drilling 100 vertical development wells this year, but have not yet found an appropriate application for horizontal technology”. They may believe this EOR process is only applicable to specific resource types (e.g., fractured carbonates similar to the Austin Chalk).  In failing to define the perfect application, the user  is reluctant to test the potential benefits that horizontal well geometry offers.

For this reason we recommend not asking where, or why, to drill a horizontal well, but inversely ask “Why not?”.  Just because one can realize an acceptable ROR with conventional vertical well development is not, singularly, a proper excuse to disregard the potential of  horizontal wells.  In fact, the more sophisticated operators now apply (either consciously, or not) an approach summarized as: We will not commit to drilling a vertical development well until we have site-specifically evaluated the potential of a horizontal well.  To perform such a test, one must apply a site-specific analysis.

SITE-SPECIFIC —  There are many general statements offered concerning the cost and benefits of horizontal wells, such as, a horizontal well should cost 2-3 times a vertical well and produce 3-4 times the rate of a vertical well.  Ref. #2 offers average production and cost ratios of horizontal wells in the U.S. (compared to vertical wells in the field).  The average cost ratio is 2, the average production ratio 3.2. The average increase of reserves derived from these horizontal well applications is quoted at 8.7%.

There are few development scenarios where a 3-fold increase in production or an 8% increase in reserves would not be an extremely attractive goal.  But these are averages of many varied applications, reservoir settings, well designs, etc.   Applying these averages to what appears to be an analogous application may lead to unrealistic expectations.  A common occurrence is that the less experienced operator drills the first horizontal well at greater than expected costs, with less than expected production.  This outcome invariably leaves management with  a bitter taste for the  technology in general, even though the well may have been a technical success.  This result is related to lack of appreciation for the site-specific nature of horizontal well applications.

Consider the typical view of a planned horizontal well provided in Figure 2. This image reflects many misconceptions.  No reservoirs are completely homogenous.  The major surprise to all earth scientists when applying their first horizontal well in a field, is the degree of lateral variation observed  within the reservoir.  Horizontal well geometry offers a new dimension in accessing and evaluating this lateral variation when compared to the point-source penetration of a vertical well.  Another image that misleads is the smooth flat shape of the planned well.  It is impossible to drill a perfectly flat well, even if desired.  In fact, the ability to shape the well within the reservoir is critical in respect to sweet-spot access,  injection/production response, workover, EOR potential, etc.

The image of flat lying fluid contacts and equally distributed reservoir pressure can also be disastrously misleading, particularly in fields where withdrawal and/or injection has occurred. This typical image is full of myths.  Every field, and perhaps each well is unique.  There is no standard reservoir/application type, no common well design, no universally applied completion, workover, or production strategy.  To rely on analogous comparison and simply apply a standard well design is to seek less than optimal, if not disastrous results.

It is now  accepted that horizontal wells must be customized and designed “backwards”.  That is, think of the long-term requirements/objectives of the well first.  These will define the site-specific workover, stimulation, and completion requirements.  Which in turn will reveal the optimum customized well design and corresponding drilling program.  This process appears backwards from a historic vertical well methodology, and opposite in sequence to actual field activities.  These issues (“where”-earth sciences, “why”-reservoir engineering, and “what”-production engineering/reservoir management) must be addressed prior to, and in conjunction with the “how”, or field operations issues.

This site-specific customization requires a multi-disciplined team, following an iterative process of screening, prioritization, design, implementation, and review.

MULTI-DISCIPLINED — This popular term appears self explanatory. But it is important to appreciate the difference  implied  in this approach compared to the typical manner of exploitation with vertical development wells. Figure 3 illustrates the key differences between these two methodologies.

Vertical well development is generally  performed in an assembly-line like  fashion, with responsibility for each progressive  facet being performed by the next department down the line.  Perhaps a geologist (earth scientist) would define the optimum location for the next development drainage point (where).  Then reservoir engineers would evaluate PI’s, recovery, ROR, etc., to prove economic viability, leading to an AFE approval (why).  A drilling (operations) department would generate a well program, organize services and drill the well (how).  A completions groups would complete, stimulate, etc., and the well finally would be  passed over to the production department (what).

This assembly-line approach may have been adequate for vertical well development, but is a proven receipt for disaster in horizontal well applications.  Countless documented field cases highlight the need for a multi-disciplined iterative approach, where all issues (where, why, what, and how) are considered, and the long-term requirements of the well are clearly defined.  The objectives of this process, illustrated on the right side of Figure # 3, is not to drill a well to prognosed TD within budget, but it seeks to define the best well type for a specific reservoir setting.  Indeed, horizontal wells do not work everywhere, thus we are attempting to define the most efficient exploitation method for the particular asset.  Success is not judged by how much well length is achieved, or at what cost, but rather what is the highest net present value per acre generated by competing well designs.  Figure #4 illustrates this economic comparison of well type for a specific reservoir, where a vertical well with fracture stimulation is a better strategic choice than a horizontal well.  The final step in this process is a post-audit which defines refinements to well design to be applied to the next well, and thus the process begins again.  This effort is not simply a choice of drilling parameters, but a balancing act of many wants and needs within a team.

TEAM —  The upstream side of our industry has gone through significant structural change over the last decade.  Rather than departments of specific disciplines (e.g., Geology Department, Reservoir Department) we now have multi-disciplined asset teams, business units, or whatever term is applied.  This organizational change looks good, particularly when horizontal technology is being considered.  However, it is easy to “say” team, but much more difficult to effectively apply a team approach.  One predominant difficulty is the lack of understanding of the inter-related effects of one team-member’s needs on another’s.

For optimum results, each member must have a basic appreciation of the requirements, capabilities, and limitations of all other disciplines represented, and technologies employed, by the team.  They must be able to understand and balance competing requirements. They should  be capable of distinguishing between general wants and critical needs.

There are many field examples of how a dysfunctional team has resulted in disaster in a horizontal well.  Figure 5 depicts the actual horizontal well, offshore South East Asia, shown as a planned well in Figure 2.  The design included a pilot hole to prove the existence/location of the target zone and evaluate its quality.  In this manner, pilot holes are a very popular “geo-steering” method.  After confirming where a viable target existed, the more expensive and operationally challenging step of drilling and casing the curve at 90°± hole inclination (landing) in the target was accomplished.

Once drilling out the casing shoe and 30 ft of quality pay, the well encountered unproductive shale, in what was assumed to be a relatively flat-lying homogeneous target.  The Drilling Supervisor asks the Well-Site Geologist, “Where do we go now?  Up, down, left?  Or do we stop?”  This is offshore, at a day rate of $250,000.  There is no time to reprocess the seismic, or re-interpret the offset well logs.  The Well-Site Geologist must answer the question now.  This common situation highlights the expanded  role of the Geologist, in fact, all Earth Scientists, in respect to horizontal well applications.

Historically, in vertical development wells, a Well-Site Geologist’s role was to evaluate what was drilled.  Similarly, logs and other evaluation technologies were employed to answer this  after-the-fact question.  In horizontal well applications, the Earth Scientists must define the direction and customized shape of the well prior to, and, as it is being drilled. To not employ site-specific geo-steering practices is to invite a technical success.  But it gets worse.

If the Geologist does not fully appreciate the capabilities and limitations of the directional drilling function, and/or if the long-term implications of well trajectory limits on completion, workover, stimulation requirements, etc., are not fully appreciated, then serious trouble can arise.  You may end up with a well placed in the target sweet-spot, but unable to install the proper completion.  This may sound extreme, but has happened in many applications around the world.  This simple example highlights why it is not only critical that all disciplines are involved in the team, but how their functions are  expanded  in horizontal well applications, and how they may have novel and significant inter-discipline cause/effect relationships.

The multi-disciplined team requirement is common sense, and on the surface appears simple to apply.  While it is very easy to say “team”, it is much more demanding to put into effect.  Often a multi-disciplined team is employed to screen the application and formulate the well design, then the project is passed over to an operations group to implement.  This can lead to trouble.  In our right-sized environment, the operations group tend to be over-worked, and often are running on auto-pilot.  They have been given a program and their job is to get the well drilled.  But, by nature, horizontal wells are full of surprises. Alterations of the plan must be made “on the fly”.  Often the operations group are not made aware of the potential for surprises in geology, structure, etc.  They may not be fully versed on the long-term impact on workover, EOR requirements, etc., resultant of the “on-the-fly” changes in well design generated by these surprises.  At the end of the day, there is no time to do a post-analysis or technical audit; thus the site-specific learning-curve benefit is not fully realized.

In the ideal world, the same multidisciplined team which screened and conceived the well plan should implement field activities and post-audit the well.  This would  help ensure that only appropriate changes are made on-the-fly, and the multiwell learning curve is utilized to develop that critical site-specific expertise.  Another very simple error is to have one program for drilling and a separate program for completion/production.  This can lead to some very embarrassing, if not ridiculously simple omissions, or mistakes.  Often a “drilling hand” is not included as part of the Asset Team.  A reality of our lean and mean times, but a clear weakness where Earth Scientists, Production Disciplines, etc., are setting drilling requirements which may, or may not, be doable, practical, or economically viable.

After countless technical audits of horizontal well applications globally, we can define some simple steps which can help promote an effective team function:

1^st Provide all team members with basic cross-functional training on multi-disciplined horizontal well technology.

2^nd Conduct a detailed pre-spud meeting with all disciplines and key service suppliers to confirm and sign-off on basic objectives, contingencies, logistics, operational authority, field operations documentation, etc.

3^rd Generate a critical post-well review that defines problems/surprise encountered, lessons learned, and appropriate modifications, additions, etc., for the next well in the field (i.e., capture the site-specific expertise).

GEO-STEERING —  This buzz-word has tremendous play in our technical media.  It is one of the most misrepresented issues.  Some of the major directional/drilling and logging service suppliers have dubbed their products as  “geo-steering systems”.  This suggests that in order to geo-steer, one must employ these  expensive and sophisticated measurement while drilling (MWD) systems.  In fact, there is legal action in progress concerning a patent on the concept of geo-steering, in respect to employing MWD sensors to dictate the direction of the well while drilling.

Basically, geo-steering refers to defining, generating, and monitoring a wellpath based on geology rather than geometry.  A globally observed major surprise to all operators is the degree of lateral stratigraphic and structure variation observed via horizontal wells.  Thus, one should not define, or implement a well design based solely on prognosed TVD, offset well control, and geometry.  These data are used to generate a “planned” well profile, but the actual wellpath must be altered as the variation in the reservoir is observed during drilling. This process defines geologic steering as opposed to geometric steering.  Employing various MWD sensors is one potential method of geo-steering, but not the only, or necessarily the best method.  Pilot holes, rate of penetration, bio-steering, gas analysis, cuttings analysis, inflow monitoring, etc., are all examples of viable geo-steering practices.  Any site-specific observation which can be made prior to, or while drilling the well to fine-tune, alter, or confirm the optimal well path should be considered as a potential geo-steering technique.

Another major misconception is that geo-steering is to be employed in the horizontal section, this could not be further from the truth.  Before one geo-steers in the target, one must first find the target.  Many wells have failed because of assumptions or over-confidence of the TVD of the target, structure, fluid contacts, etc.  In many cases the operator could not find the target, or had to dramatically alter the initial curve design to land in the target.  Thus geo-steering must be initiated prior to the horizontal section.  In essence, you are looking to land the well in a moving geologic target, and you can never be 100% sure of exactly where/what it is, until you find it.

The optimum geo-steering methods to use on any given horizontal well are defined by: