CATEGORIZED | 2010, March/April

To truly improve drilling efficiency, ROP is only one among many performance qualifiers

Posted on 24 March 2010

By Graham Mensa-Wilmot and Yoseph Harjadi, Chevron – MAXDRILL Team

Editor’s Note: This is the second in a two-part article on one operator’s perspective on performance drilling and how operators can improve drilling efficiency and ultimately reduce operational costs. Part 1, “Performance drilling – definition, benchmarking, performance qualifiers, efficiency and value,” was published in the July/August 2009 issue of Drilling Contractor.

Figure 1: Well A was drilled by identifying, analyzing and ranking all performance qualifiers to achieve drilling efficiency, while on Well B the strategy was simply to maximize ROP by increasing WOB. Here, the dull conditions of the same type of bit used on the two wells can be seen and compared.

Figure 1: Well A was drilled by identifying, analyzing and ranking all performance qualifiers to achieve drilling efficiency, while on Well B the strategy was simply to maximize ROP by increasing WOB. Here, the dull conditions of the same type of bit used on the two wells can be seen and compared.

Drilling efficiency must be improved in order to drive down operational costs. This requirement must not be viewed in isolation, considering the vast number of activities that determine a drilling program’s success. Most discussions relating to drilling efficiency have centered on rate of penetration (ROP). As a result, ROP is either equated to drilling efficiency or seen as the parameter that establishes drilling efficiency.

These positions are flawed and highly inconsistent with field results. ROP must not be equated to drilling efficiency. Rather, it is one of several parameters that influence drilling efficiency.

The industry’s most common performance-quantifying metrics – cost/ft (CPF), ft/day (FPD) and mechanical specific energy (MSE) – are strongly influenced by ROP. These relationships complicated earlier efforts that sought to establish the appropriate dependencies between drilling efficiency and ROP. To drive down operational costs while continuing to push drilling into harsher and more challenging environments, emphasis must be clearly placed on drilling efficiency.

To achieve this goal, drilling efficiency and ROP must both be defined, and factors influencing ROP and drilling efficiency must be identified. Most importantly, drilling efficiency’s different influencing factors, which include but are not limited to ROP, must be analyzed based on specific project objectives.

This article will address these issues and establish a distinction between drilling efficiency and ROP. In addition, the contributions and impact of both ROP and drilling efficiency, as it relates to value creation, will be discussed. Field and operational data will be presented.

BACKGROUND

The perceived effects of ROP on drilling efficiency, compared with actual field situations, highlight certain critical issues. Drilling efficiency is claimed to improve when ROP increases and asserted to deteriorate when ROP declines. As a means toward drilling efficiency improvement, ROP-enhancing strategies are devised and implemented. However, increases in ROP, even when their perceived effects on drilling efficiency are accepted, have not always had the desired results on operational costs.

Consequently, ROP increases cannot be assumed to always have positive effects on drilling efficiency. This realization exposes a weakness in the current ROP-versus-drilling efficiency relationship.

Drilling efficiency will have the desired effects on costs when all critical operational parameters are identified and analyzed. These parameters, referred to as performance qualifiers (PQ), include footage drilled per BHA, downhole tool life, vibrations control, durability, steering efficiency, directional responsiveness, ROP, borehole quality, etc. As part of the evaluation process, these PQs must be awarded their rightful levels of importance based on the defined project objectives.

To improve drilling efficiency, PQs should not be analyzed in isolation because they are interrelated. Consequently, maximization of any particular PQ, without identifying and addressing the effects the effort has on the other PQs, always compromises drilling efficiency. Earlier efforts to improve ROP often did not address these concerns.

These observations explain ROP’s weak and inconsistent effects on drilling efficiency. It is not sufficient to merely expose ROP’s limitations. Rather, systematic processes that ensure complete understanding and effective evaluation of all PQs must be developed.

RATE OF PENETRATION

ROP is defined as advancement in unit time while the drill bit is on bottom and drilling ahead. Although important, ROP improvement must not compromise other PQs. Regardless of project type and/or drilling program, the PQs are always the same. However, their ranking and importance vary from project to project. Consequently, ROP can have different rankings with regards to its effect on drilling efficiency.

Most of the factors that affect ROP (FAROP) have influencing effects on other PQs. Based on the current discussion, these factors can be grouped into three categories – planning, environment and execution. In the planning group are hole size; well profile; casing depths; drive mechanism (PDM, RST, turbine); bits; BHA; drilling fluid type and rheological properties; flow rate; HSI and hole cleaning, etc. Lithology types, formation drillability (hardness, abrasiveness, etc), pressure conditions (differential and hydrostatic) and deviation tendencies are the environmental factors. Weight on bit (WOB), RPM and drilling dynamics, belong to the execution category.

There are two main types of ROP – instantaneous (ROPi) and average (ROPav). Instantaneous ROP is measured over a finite time or distance, while drilling is still in progress. It gives a snapshot perspective of how a particular formation is being drilled or how the drilling system is functioning under specific operational conditions. Average ROP is measured over the total interval drilled by a respective BHA from trip-in-hole (TIH) to pull-out-of-hole (POOH).

Figure 2 compares the ROP (main PQ) and footage achieved on a drilling campaign against the initial benchmark (Well A) in the West Africa case study. Even though more footage was drilled in the same hole section on the other wells (compared with the offset), ROP improvements were achieved without compromising the other PQs.

Figure 2 compares the ROP (main PQ) and footage achieved on a drilling campaign against the initial benchmark (Well A) in the West Africa case study. Even though more footage was drilled in the same hole section on the other wells (compared with the offset), ROP improvements were achieved without compromising the other PQs.

FAROP

FAROP’s elements usually have positive effects on instantaneous ROP. However, depending on how it is achieved and its duration, this benefit does not guarantee improvements in average ROP. In addition to possibly having a direct negative effect on average ROP, FAROP can also have an indirect effect on average ROP based on its effects on other PQs.

In all ROP discussions and evaluations aimed at improving drilling efficiency, the emphasis must always be placed on average ROP.

The understanding and application of FAROP, in order to achieve its desired effects, is very subjective. This issue sometimes creates misinterpretations with regards to the effects and consequences of FAROP elements. However, FAROP’s effects on ROP and drilling efficiency cannot be disputed. The most critical questions that need to be answered are: Which ROP is FAROP impacting? And what effect does that specific ROP have on operational costs?

As an example, WOB, when elevated, usually increases instantaneous ROP. However, drilling efficiency improvements are dependent only on average ROP. As a result, ROPi achievement must be converted into ROPav gains. To achieve this objective, these questions must be answered:

• Was the drilling system designed (bit, BHA, drive system) to allow for the WOB increase?

• Can the FAROP categories (planning, environment and execution) accommodate the ROP gain?

• Has an efficient action (WOB increase) versus reaction (ROP gain) relationship been established?

• Considering the footage to be drilled and the ROP-versus-WOB relationship, will the drilling system get to the planned section TD or POOH depth?

If the answer to any of these questions is no, then the ROP gain, achieved with the WOB increase, will be short-lived.

In such instances, the secondary repercussions of the instantaneous ROP gain end up negating the intended benefits. The increased instantaneous ROP, by being short-lived, leads to unplanned events – to change out bits or other tools, not being able to get casing to bottom, or poor cement jobs. ROP improvement, to have the desired effect, must be sustainable over the planned interval that is to be drilled.

The same arguments will be valid for most of FAROP’s elements.

DEFINITIONS

To achieve drilling efficiency, certain basic requirements and conditions must be met. The primary objective must be geared toward the lowest cost per section and, ultimately, the construction of usable wells. In this regard, the sources of nonproductive time (NPT), namely visible lost time (VLT) and invisible lost time (ILT), must be analyzed in detail.

Considering this article’s central theme, this commitment must ensure minimization of drilling-related inefficiencies, or ILT. In addition, certain drilling-related unplanned events, which fall into the VLT category, especially trips associated with bits, BHAs, downhole tools and drive systems, must also be analyzed. To move the discussion forward, the ILT and unplanned events will be referred to as factors that affect drilling efficiency (FADE).

The relationships and contributions of FADE must be understood in order to achieve drilling efficiency and drive down operational costs. As a first step, drilling efficiency is now defined as “the construction and delivery of a usable well while achieving the operational conditions needed to achieve the lowest cost imprint.”

It is worth noting that the PQ elements belong to the FADE group.

FAROP AND PQ EFFECTS

There is no specific mention of ROP in the definition of drilling efficiency. However, there is a requirement to achieve a reduced cost imprint, which is where the PQ elements come in. What is worth noting is that FAROP’s elements influence all the different PQs, and all PQs are interrelated. These realizations, in addition to forcing a re-evaluation of the mechanical and operational influences, also govern how drilling efficiency is viewed and achieved.

As an example, increased RPM usually leads to instantaneous improvements in ROP. This action and associated ROP gain could also lead to the initiation of vibrations, depending on the bit type, BHA design, formation types, other operational parameters, and well profile.  The vibrations could end up causing damage to the drill bit, which sacrifices bit durability. Due to the induced damage, ROP becomes compromised. It is worth noting that impact damage and durability are not the same. However, impact damage reduces durability.

In this example, the intended ROP gain from the RPM increase was indirectly compromised due to the associated bit damage. Although RPM was used in this example, most of the FAROP and PQ elements, when paired for similar discussions, will yield comparable results.

In addition to the FAROP discussions and effects, the PQ elements must be achieved in their ranked order on a project basis. For all purposes, this is the most critical requirement in discussions relating to drilling efficiency.

In instances where ROP is identified as the most important PQ, the drilling system’s design, together with the execution practices, must facilitate achievement of this objective. The other PQs will still be relevant, though to lesser degrees compared with ROP. If the conditions needed to improve ROP create negative effects on other PQs, the ROP gain will not improve drilling efficiency.

As an example, ROP improvement in a long tangent section, achieved at the expense of directional responsiveness or steering capability, will not improve drilling efficiency. Likewise, ROP improvements achieved at the expense of bit durability or borehole verticality will not improve drilling efficiency.

Regardless of application or project type, achievement of operational objectives must always outweigh the mechanical considerations. Such a strategy will always improve drilling efficiency. In addition, the mechanical considerations must be evaluated as part of the PQ discussion because ROP is one of several PQs.

As argued here, ROP and drilling efficiency are not the same. Maximization of instantaneous ROP is easy, but that is not the real issue. Achievement of PQs in a ranked order, based on their effects and contributions to drilling efficiency, is the ultimate challenge.

VALUE CREATION

In all situations, improvements in drilling efficiency must always drive down operational costs. This requirement must be achieved and quantified on a section-by-section basis. Consequently, data analysis, aimed at comparing offsets with new projects, must be executed continuously. Value creation (VC), expressed as a percentage, can be defined as the ratio between planned (AFE) and actual spends.

Planned spend (AFE) is usually determined from offsets. The offsets, based on when they were drilled, technologies used, planning and execution principles, may have had dysfunctions. As is well known, exploration wells present different challenges. Limited and/or unreliable data usually complicate AFE determinations.

In addition, unknowns associated with the drilling environment can obscure this issue. Consequently, initial AFEs can be higher than the actual spends incurred on new projects (zone A). This anomaly creates an initial VC value that may be higher than actual.

As drilling projects evolve in terms of well count, AFE values may decrease and provide less differential between actual and planned spends. In addition, and considering drilling efficiency’s effects, actual spend (AS) is also expected to go down. However, deepwater operations, based on their unique challenges and unknowns, may still have unpredictable AFEs, regardless of well count.

Drilling efficiency’s impact on value creation is more accurate when measured in a consistent AFE zone. PQ analysis and ranking is a dynamic process. As value is continuously created and experience is gained as to why and how progress is being made, PQ rankings also change for similar projects.

ROP may go from being lowest-ranked based on project phase and associated risks, to an intermediate value, and finally to the highest slot on subsequent wells. Throughout this evolution, the other PQs must always be considered. Even in instances where ROP finally captures the highest priority and project objectives are being met, ROP still has to be improved from project to project in order to continuously create value.

Any other PQ, when substituted for ROP in this discussion, will offer similar discussions. What is important is an understanding of how the process works, the expectations and how they are achieved, not the highest-ranked PQ.

VC is strongly dependent on data analysis. Through this process, several determinations with strong impact on drilling efficiency can be made. In some instances, and based on the time percentages (distributions or difference) between total well NPT and on-bottom drilling time (OBT), drilling efficiency is discounted as an area of focus for cost reduction. However, an NPT breakdown by function, coupled with a detailed review of the “action-versus-reaction” sequences, usually depict different conclusions. Several NPT events (outside of rig and geologic events) can be linked to OBT activities. The OBT consequences can also be linked to planning and system design decisions.

As a result, all FADE and drilling NPT factors associated directly or indirectly with not achieving the PQs or overall section goals will be classified as drilling nonproductive time (NPTD).

OBT is usually small when expressed as a percentage of total drilling time (TDT).  As it relates to the drilling operation, section TDT is defined as the total accumulated time from picking up the section BHA until the section is drilled to total depth (TD), the BHA is out of the hole, and the team is preparing to rig up and run casing.

However, if a section is drilled and it is not possible to get casing to the desired depth because of borehole quality issues, due to poor drilling practices or drilling system design, the lost efficiency must be assigned to NPTD.

Based on the above discussions, the following questions need to be answered:

• Is the current TDT reflective of the project at hand?

• Have all FADE avenues been evaluated?

• Have NPTD reduction strategies been identified?

• Have strategies been identified that will increase OBT?

From a drilling efficiency standpoint, the answer to the first item should always be no. The answers to the next three items (after detailed data review) must always be yes. Such an approach to data use and execution of the strategies identified will increase OBT when expressed as a percentage of TDT.

Figure 3 depicts the worn conditions of the bits used in the West Africa drilling program.

Figure 3 depicts the worn conditions of the bits used in the West Africa drilling program.

Drilling efficiency gains, accompanied by drastic reductions in operational costs, are achieved when OBT grows and NPT (specifically NPTD) decreases. The OBT gain should not be seen as a reduction in ROP. It just means that the operation is progressing more efficiently.

Moving forward, OBT values should not be used as disqualification criteria for drilling efficiency improvement. Value can always be created; there is no technical limit.

FIELD CASES

The concepts described have been executed on several projects worldwide.  Two will be discussed in this section to address different parts of the argument.

Field Case A: drilling efficiency vs ROP, Mid-Continent US

Data for two 8 ½-in. sections drilled in the same field and through the same formations (Wells A and B) are compared. On Well A, a single BHA drilled 6,681 ft to section TD at an average ROP of 98 ft/hr. Well B, drilled with much higher WOB values, required a BHA trip to complete the same section. The first and second BHAs on Well B drilled 5,452 ft at 89.4 ft/hr and 479 ft at 14.5 ft/hr, respectively.

In evaluating the sections drilled on the two wells, direct comparisons can be made between Well A and the first run on Well B. Drill bits, drive systems and BHAs were similar on both runs.  Although the intent was to achieve drilling efficiency and drive down operational costs, different approaches were used on the two runs.

Well A followed the principles described in this paper. The PQs were identified and analyzed, with borehole verticality, vibrations control, single BHA runs and footage occupying more important ranks than ROP. In addition, the relationships between the ranked PQs were analyzed for their indirect effects.

For Well B, the strategy was to achieve drilling efficiency through ROP maximization by increasing WOB. The average WOB values, used on Well A and the first run on Well B, were 10,000 lbs and 16,000 lbs, respectively.

The initial ROPs were higher on Well B, as will be predicted. However, and as discussed earlier, WOB’s complete effect on ROP was not addressed (note the four questions that must be answered in all instances). In addition, ROP’s interdependencies with the other PQs were not analyzed. Consequently, the WOB elevation compromised the other PQs, including vibrations and bit durability, which ended up forcing a BHA trip to change out the bit.

The initial ROP gain could not be converted into an increased average ROP.  The dull conditions of the identical bits used on the two runs are shown in Figure 1. Subsequent wells drilled on this campaign, following the strategies discussed in this article, achieved results that were similar to that realized on Well A. Total savings for this hole size exceeded US$300,000.

Field Case B: ROP as dominant PQ, West Africa

This project focused on an 8 ½-in. interval on the West Coast of Africa and followed the principles discussed in this article. After evaluations of the offset data and identification of relevant PQs, ROP was deemed the most critical.  FAROPs effects, as well as the interrelationships between the other PQs, were also analyzed.

Even though more footage was drilled in the same hole section on the other wells (compared with the offset), ROP improvements were achieved without compromising the other PQs. The achieved ROP improvements and the footage drilled, compared with the initial benchmark, are shown in Figure 2.

In addition, the dull conditions of two of the bits used on the drilling campaign are shown in Figure 3. In all situations, FAROP’s elements met the four conditions identified earlier. In addition, PQ analysis and re-ranking (outside of ROP, since this parameter was assigned the highest importance), was always executed. For the hole size presented in this discussion, total savings on the four wells was in excess of US$3.9 million.

CONCLUSIONS

• Most of the industry’s performance-quantifying metrics are strongly dependent on ROP.

• Factors affecting ROP (FAROP) can have direct negative effects on ROP if certain conditions are not met.

• Drilling efficiency and ROP are not the same. Their effects on operational cost reductions are different.

• ROP is one of several performance qualifiers, not the only factor that influences overall section or well drilling efficiency.

• PQs are interdependent and must be analyzed in unison.

• FAROP elements have indirect effects on ROP, due to PQ interdependencies.

• ROP improvement does not guarantee enhancements in drilling efficiency.

• Performance qualifiers must be identified and ranked on a section-by-section basis, depending on specific drilling program objectives.

• Strategies developed to achieve higher-ranked PQs must not compromise the lower-ranked PQs.

• Improvements in drilling efficiency always guarantee reductions in operational costs.

Additional supporting graphics and images are available in the online version of this article at www.DrillingContractor.org.

IADC/SPE 128288, “Drilling Efficiency and Rate of Penetration – Definition, Influencing Factors, Relationships and Value,” was presented at the 2010 IADC/SPE Drilling Conference & Exhibition, 2-4 February, New Orleans, La.

Acknowledgements: The authors will like to thank John Connors, Mustapha Dikko and Gust Woldtvedt, all of Chevron, for their contributions, commitment and support to the concepts and discussions presented herer. Special mention also goes to Bill Thornburg and the entire Transocean Discoverer Deep Seas drilling operations team.

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