Bob Knoll – H-Tech Petroleum Consulting

MPD Well Taps Light Oil in Deep Monterey Shale

Bob Knoll — Fri, 04 Mar 2011 07:56:45 +0000

Below 10,000’, a horizontal well drilled on-shore southern California, applies novel Managed Pressure Drilling technology to prove the potential of a basin wide resource. Over 2,200’ of fractured light oil shale is horizontally accessed using a concentric-string air injection system and a simple water-based drill-in fluid.

Bob Knoll, Maurer Technology Inc (Division of Noble Drilling)

1.1 Background

This well was drilled by California based Temblor Petroleum Company LLC, with support from the U. S. Department of Energy “Demonstration Well“ funding program. The project was undertaken to demonstrate that oil and gas can be explored, drilled and produced safely and economically from a deep fractured Monterey reservoir in the Santa Maria Basin of California by employing cutting-edge horizontal and MPD drilling methods. Two wells were previously drilled vertically in this area with heavy mud and completed conventionally. Neither well was commercially productive after fracture stimulation attempts, even though very strong shows of oil and gas were obtained while drilling, and free oil and gas were recovered from both wells during and after completion. Seismic and well data indicate a structural trap, a down-thrown fault block or graben, of some 1500 acres, providing a potential accumulation of 30 to 50 million barrels of 31 gravity oil, and 30 to 50 BCF of gas.

The new well (Castillo, Ross and Howe 2-19) was drilled on the location: SEC 19 T8N R32W, Santa Barbara County, California, in the fall of 2004 (Figure 1). The project’s objective was to horizontally access a minimum of 2100 ft of oil-bearing, high-resistivity Monterey shale. The Monterey is a fractured/micro-fractured Miocene reservoir that has produced most of the oil and gas in the Santa Maria Basin onshore region of south central California. The target reservoir is at a depth exceeding 10,000 ft true vertical depth (TVD). All commercial onshore production from the high-resistivity section of the Monterey has come from fields at much shallower depths – 5000 ft TVD or less.

The original discovery well, drilled by Oxy in 1986, penetrated and logged approximately 700 ft of a light oil column at 10,500 ft TVD. Temblor drilled a second delineation well in 1999 from a new surface location approximately 0.5 mile southeast of the discovery well surface location. This second well was directionally drilled (30° inclination) so that its bottom-hole location was only 400 ft laterally displaced from the discovery well within the Monterey target interval. The second well also logged approximately 700 ft of light oil column with no evidence of bottom water or top gas.Although the well flowed for a short period (10 BOPD for 1.5 hours), it would not sustain commercial flow rates after an acid stimulation treatment, and was suspended.

Both original wells were vertical to sub-vertical, and it appears only the first “discovery” well was near to (or accessed) a set of natural vertical fractures. Fractures are clearly seen in nearby outcrops and are expected to trend NE–SW within the Monterey due to the local stress state.

The new well employed many novel design attributes and MPD procedures to avoid this potentially damaging process, to mitigate unstable shale problems, to provide faster penetration rates (P-rate), and to allow for simple “Evaluation-While-Drilling” (EWD) observation of oil-filled fracture access. Successful exploitation of this structure by horizontally accessing vertical fractures in a non-damaging mode was expected to deliver production of ±600 BOPD.

Novel Well Design Aspects and Results;

One novel attribute of the well related to the 10.75” surface casing / 7” concentric “slave” string design. The term “slave” refers to an extra concentric casing string suspended from the wellhead to provide a number of unique capabilities. In this application the slave string was stabbed into a 7” liner that had been run and cemented at the heal of the well @ 10,000’ TVD and 60° angle. The liner hanger was set at 3,300’ TVD just inside the surface casing shoe (Figure #2 below). The slave assembly included a ported sub directly above the liner stab-in assembly. This design provided a temporary annular flow path for air-lift injection, and an area for secure placement and control of a “Down-hole Deployment Valve- (DDV) set directly above the ported sub. The DVD, when function closed, would allow conventional tripping above the valve while maintaining the horizontal interval in a balanced/under-balanced bottom-hole-pressure (BHP) condition. Once drilling the entire horizontal productive interval in a controlled MPD mode, the slave/DVD assembly was retrieved and the 7” liner was conventionally tied back to the surface wellhead.

Figure #2, Slave String and DVD design and placement.

This novel approach, figure #3 below, provided capability for concentric string air-injection MPD without the requirement of special motors/MWD/LWD equipment or practices necessary when conducting MPD with conventional aerated fluids. The use of air also provided significant cost savings versus nitrogen.

This MPD approached worked very well in drilling the horizontal section, particularly once optimum air injection rates were established. The reservoir pressure was expected to be in the 5000 PSI range. The targeted BHP range of around 4600 PSI were generated during drilling and verified by measurements from an annular pressure sub on the directional drilling assembly.

Improved P-rates were gained as a direct function of the reduced BHP while drilling horizontally in the shale. This effect is clearly seen in figure #4 below, comparing instantaneous drilling rate with air-injection rate and corresponding reduced BHP observations.

(FIGURE 4)

Fluid Selection;

A relatively costly oil based mud (OBM) was initially considered necessary in the intermediate vertical and upper curve-to-heal section to mitigate shale stability problems. The larger then normal intermediate hole size (9.825” versus the more standard 8.5” hole for 7” liner installation), allowed by the larger surface casing, provided an enlarged annular clearance for the 7” liner. This, in turn, allowed for use of a simple pre-weighted water-based fluid in the intermediate hole section. This approach was proved viable, from a shale stability perspective, since the Sisquoc shale in the intermediate hole section was exposed for more then 17 days prior to liner installation, and the 7” liner was run to bottom with little trouble after a reaming run of the intermediate and upper curved section.

The use of simple water base in both the curve and horizontal section also proved very valuable in terms of EWD. A seismic anomaly suggested a fault or fractured zone may exists at the top of the Monterey target. P-rate variation, mineralogy of cuttings, and strong Hydrocarbon shows all pointed to access of an oil-filled fractured zone at this point. The upper curve was terminated at this point and lined with 7” liner. The main 6.125” horizontal section was then placed and completed as an open hole, employing a short tangent section to get deeper into the high resistive interval of the shale, then a lower curve was built to a 90° angle and a horizontal section drilled to close proximity and beyond the discovery well bottom hole location.

A basic challenge of the well was stabilization of the deep Monterey Shale to protect the integrity of the hole and to allow cuttings to come to the surface in good enough condition to allow EWD. This implies a visual inspection of the drilled cuttings for micro-fracturing and oil within the fractures, and is calibrated with the mud-gas logging observations, drilling rate changes, etc. The target high resistivity shale is a gradation between chert, argillaceous chert and siliceous shale and should not require stabilization. The bounding upper and lower Monterey units are less siliceous and thus shale stabilization may be attractive in theses intervals.

Typically, shale stabilization is accomplished by adding 4% KCl to the drilling fluid. A concentration of 4% KCl provides maximum shale inhibition, but is also the point of maximum corrosion enhancement, the risk or corrosion problems is dramatically accelerated by injection of air. This much salt also leads to special drilling waste disposal requirements. The problem was successfully resolved on this well by the use of a “KCl Substitute” ─ TEA (tri-ethylene methyl-chloride), in concentrations of 0.1% by volume in the drill-in fluid. Unlike KCl, TEA does not require the extensive use of corrosion inhibitors. The use of TEA resulted in good hole condition in the productive/horizontal interval. There was no trouble with shale stabilization in the productive interval and the cuttings, while very small, did not appear to be significantly hydrated or altered. There was a significant cost saving gained by minimal use of corrosion inhibitors with no apparent corrosion of the drill pipe.

Having a simple water-based fluid provided very clear observations of drilled oil and mud-gas spikes as fractures were crossed. A gamma-ray sensor was also employed in the h-section, but was less effective in detecting fracture crossings. The mid section of the h-length appeared void of fracture crossings, while the far end accessed multiple fractures as it passed the original well bottom location.

Field Performance & Conclusions

Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. The Operator is currently investigating the costs and operational viability of re-entering the well and conducting an FMI (fracture detection) log and/or an acid/frac stimulation.

Figure #5 above compares the planned and actual well path, figure #6 below provides a time/cost comparison between planned and actual performance.

The drilling time sheets indicate that the total “problem time” experienced on the well accounted for only 3.8% of total field operations. This definition of problem time is very subjective. From the authors’ perspective, there was a larger proportion of time lost due to avoidable errors and less than optimal operational decisions made on sight. The delays on the well were primarily due to a combination of:

A – Slower than anticipated penetration rates in both the intermediate and productive hole sections. The merit of PDC bits appeared attractive in this application. This was evidenced by the superior performance gained by this bit type in both the intermediate and productive sections versus conventional rock bits.

B- Slower than expected rig operations with numerous equipment failures, and extended liner and tie-back operations stemming from a failed primary cementing job and a space-out error in slave string placement.

C- Numerous trips for failed motor and MWD assemblies in the productive interval. The bottom-hole pressure expectation of 250-260°F were discussed with the service provider, however, the adequate supply of appropriately designed and serviced motors must be challenged given the frequency of motor/MWD failures experienced (5 motor/MWD failures in the h-section).

Conclusions;

A – Horizontal, MPD applications are viable in these deeper HRM targets. The existence of conductive fractures/micro-fractures and sustainable dual-porosity reservoir pressure may be prerequisites for success.

B – The novel MPD drilling mode merits expanded application in this general setting. This drilling method provided good EWD capability, faster penetration, and minimal formation damage concern.

C – PDC bit application and customization should be more aggressively pursued in deep Monterey drilling projects.

D – Very stringent focus is required to ensure key staff continuity between planning and field operations phases. Properly briefed and adequately relieved field supervision providing 24 hour coverage is a necessity when conducting novel well construction operations. These field supervisors must strive to ensure that an open and effective “team” effort exists, particularly when novel drilling operations or well designs are being employed. With proper procedural planning of novel activities, the team is confident that similarly designed wells could be constructed in 30 days or less, with costs in the order of 50% of that experienced on this well.

Hints on Horizontal Technology

Bob Knoll — Fri, 04 Mar 2011 02:41:55 +0000

The advancement of exploitation technology over the last decade is unprecedented in our industry, but appears to have led to a disparity between those that have leveraged these advanced well designs in their assets, and those that are hesitant to embrace the novel methodologies. The author has had extensive exposure to both groups throughout North America, and can identify misconceptions common in the latter group that may impede their application of these more aggressive exploitation strategies. Suggested challenges to some of the more prevalent mindsets are summarized in this article.

Recently the author has delivered an extensive series of 1-day management seminars targeted at independent operators interested in applying horizontal, (H-well) and other advanced exploitation technologies in marginal resource settings. A common attitude generally expressed by this operator group could be summarized as; “H-wells are best suited to the major operators exploiting prolific, high profile (cost) development settings. This advanced well type is too technically challenging, too expensive and risky for a small operator in a marginal resource. We can make reasonable ROR with conventional vertical wells of known cost and acceptable risk, so why bother with these more challenging well designs?”

Although these issues appear valid at first glance, one should examine the assumptions deeper before discounting the wide range of benefit potentially delivered by horizontal technology. One must expect higher costs and operational risks with H-wells, but this does not mean they are viable only in the high cost, prolific field settings.

One need only look at the collective industry experience of the Western Canadian Basin, where there are approximately 16,000 horizontal wells in operation. It is difficult to quote exact numbers due to the lack of an industry-wide accepted definition. This industry is relatively small, ranked 11th in conventional oil production globally. It is generally characterized by what would be considered low cost, marginal resources compared to typical development settings globally; yet holds a dominant position with respect to rate and diversity of horizontal well applications.

In fact, one could logically argue that, in general, the more marginal the setting, (thinner, tighter, depleted), the better a horizontal investment versus a vertical well. The inherent ability to access laterally discontinuous reservoir amplifies the benefit compared to a vertical well in heterogeneous reservoirs. The dramatically improved utilization of reservoir push energy, (pressure), implies that the more depleted the field, the greater the rate and recovery increase delivered by an H-well. Some of the more exotic production processes are only possible with H-wells, (e.g.; SAGD), and thus allow exploitation where conventional well/production systems are not viable. The consolidation benefits in respect to surface disturbance, OPEX reductions, reduction of lease reclamation liability etc., are all secondary benefits that could make or break a development.

We recommend that the basic mindset must be challenged. Rather than ask “why bother”, the operator might ask “why not” drill an H-well. If one is going to invest capital on exploiting a resource, should one not evaluate and strive to maximize the total value added of the application on a specific asset and per acre basis? There are simple commercial models that allow this form of NPV screening. Thus a reasonable assessment of value added delivered by competing well types can be preformed as a first step in the exploitation pursuit. There are wide ranges of design and implementation applications that allow the operator to define and mitigate the operational risk aspects on a site-specific and well-specific basis. So both the cost/benefit and well construction issues can be cost effectively addressed in marginal setting applications.

In high profile settings, (eg; deep-water developments), all well costs will be elevated compared to a marginal onshore setting. Therefore the incremental cost of h-wells versus vertical/directional wells is not a major component or hindrance. This makes horizontal wells in high cost settings relatively easy to justify. But when the CAPEX is tripled, or worse, by employing a horizontal well in a low cost environment, it is a much tougher sell. The independent operator may observe all the “high end” technology incorporated in the high profile applications, and may conclude that they are a necessary component of H-well success. But this is not always the case. In fact, in many applications, the less complex the design, the higher the h-well chance of both technical and economic success.

Another barrier often anticipated is the lack of expertise in screening, designing and implementing this general well type. The multinationals have extensive global experience in developing and applying this technology. How can a small independent operator compensate for this lack of intellectual resource? The key to this is the site–specific nature of successful H-well application. Yes, it’s true that an independent in Lansing Michigan will not have the luxury of Exxon’s collective global expertise; but that expertise has relatively minor relevance to the viability or optimization of an H-well in Lansing. In fact, it is the years of hands-on experience and insight to the local setting that represents a key component of success. The local operator must apply this site-specific experience to customize design and thus maximize value in his limited resource. But first he must become conversive with the basic dos and don’ts, the universally repeated failure modes pervasive in H-well applications.

This does not necessarily imply years of lab study, simulation or 3-d visualization; but rather applying relatively simple principles with respect to the site-specific keys of the resource and application setting. The explosion of this technology has spurned a wide spectrum of low cost solutions to the technical challenges inherent in h-wells. Familiarity with these rapidly evolving options is a prerequisite of optimized application.

The smaller, independent operator often expresses revelation when first exposed to the definition of basic application “needs” versus technical discipline “wants” related to H-wells. Not all successful H-wells must employ smart or even conventional completions, nor need they be constructed underbalance and guided with state-of-the-art LWD drilling assemblies. The bottom line to economic success is to arm the site specific, multi-disciplined team with basic training and tools; so that they can properly define the application critical needs and avoid the common failure modes. The small independents can’t afford three economic or operational failures to get up the steep learning curve to optimize a specific application. They must get exposed to the proper methodology of screening, design and implementation before mobilizing a rig and learning in the field. A small investment in time to acquire this exposure is key to successful H-well application in all settings, particularly in marginal fields.

H-wells offer potential value added to almost all reservoir settings. They should be at least considered as an option in any development investment. They do cost more and imply higher operational risk, and they do not work everywhere. But the operator can effectively evaluate the cost/benefit balance, and properly address the site-specific operational concerns of any potential application. With a minor investment in time, and arming the team with a few simple tools, the value-added potential of H-wells can be leveraged to marginal assets.

Buzz Words in the Upstream – March 1998

Bob Knoll — Fri, 04 Mar 2011 02:26:53 +0000

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:

• the site-specifics of geology, structure, reservoir, and drilling parameters;

• the latitude in well trajectory limits relative to all the long-term requirements of the well;

• the capability, availability, cost, and technical risk of employing various methods in specific sections of the well. The issue of cost does not refer only to the day-rates incurred, but also the economic risk involved. One recent example revealed an operator’s loss of two complete geo-steering directional drilling systems in a problem curve. The lost-tool replacement bill was in excess of $1.5 million;

• site-specific expertise — it is highly unlikely the first well in a field will encounter 100% sweet-spot along the horizontal interval. However, with multiwell field experience, site-specific geo-steering contingencies can be defined to dramatically improve the quality, and dramatically reduce the cost/complexity of geo-steering requirements.

SUMMARY AND CONCLUSIONS

Many economic failures, or less than optimal technical successes, have occurred when inappropriately, or inadequately applying horizontal wells. Numerous “buzz” words and “general statements” can be misleading and may evoke unrealistic expectations.

Horizontal wells do not simply represent an advanced drilling technology, but rather an important exploitation process. They do not work everywhere, there is no standard, or typical application, or well design. To be optimal, horizontal applications must be screened, designed, and implemented backwards by a multi-disciplined team dealing with site-specific issues and developing site-specific expertise. Teams are easy to assemble, but require basic cross-training to properly function. A dysfunctional team is a common failure reason in horizontal well applications. Geo-steering is not the use of MWD geophysical sensors to tract the horizontal well, but a critical selection from many potential site-specific observations, to design and guide a specific wellpath into and within a moving geologic target.

An attempt is made to define and illustrate examples of misleading or misunderstood buzz words popular within modern upstream technology. Others include: underbalanced drilling, CT drilling, multibranch wells, negative skins, open-hole completions, etc. One should have a detailed understanding of the capabilities and limitations inherent in the technologies described, or the issues referred to, by these general terms. To apply these technologies without such appreciation may represent a danger to your economic health.

About the author: R.G. (Bob) Knoll is President of H-Tech. in Calgary, and the Canadian representative for Maurer Engineering Inc. (MEI) — the managing group for numerous Drilling Engineering Association (DEA) joint industry projects. Bob’s 25-yr. career is uniquely diverse. A graduate Geologist from Nova Scotia, he started off as a Maintenance Roustabout on first generation semi-submersibles operating offshore Canada. After working up the drilling contractor side of the industry to a Tool-pusher level on offshore drilling projects globally, Bob moved over to the operator side as a Drilling Engineer for Dome Petroleum in the high Arctic. Another series of global postings and advancement to OIM level led to a Senior Drilling and Completions Specialist position for Husky Oil in Calgary, studying emerging horizontal well technology.

Revision 2/Title Changed — March 23, 1998