IADC/SPE Copyright 2010, IADC/SPE Drilling Conference and Exhibition

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1 IADC/SPE Drilling Efficiency and Rate of Penetration Definitions, Influencing Factors, Relationships and Value Graham Mensa-Wilmot, Yoseph Harjadi, Sheldon Langdon, Jay Gagneaux, SPE, Chevron Corp Copyright 2010, IADC/SPE Drilling Conference and Exhibition This paper was prepared for presentation at the 2010 IADC/SPE Drilling Conference and Exhibition held in New Orleans, Louisiana, USA, 2 4 February This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright. Abstract 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. In most instances, discussions relating to drilling efficiency have centered on rate of penetration () 1,2. As a result, is either equated to drilling efficiency, or seen as the parameter that establishes drilling efficiency. These positions, in addition to being flawed, are highly inconsistent with field results. must not be equated to drilling efficiency. Rather, needs to be seen as one of several parameters that influence drilling efficiency. The industry s most common performance quantifying metrics cost per foot (CPF), feet per day (FPD), mechanical specific energy (MSE) 3,4, etc are strongly influenced by. These relationships complicated earlier efforts that sought to establish the appropriate dependencies, between drilling efficiency and. To drive down operational costs, while continuing to push drilling activities into harsher and more challenging environments, emphasis must clearly be placed on drilling efficiency. Thus, in order to achieve this goal, drilling efficiency and must both be defined. In addition, the factors influencing and drilling efficiency must be identified. Most importantly, drilling efficiency s different influencing factors 5, which include but are not limited to, must always be analyzed based on specific project objectives. This paper, in addition to addressing the issues listed above, will also establish a clear distinction between drilling efficiency and. In addition the contributions and impact of both and drilling efficiency, as it relates to value creation will be discussed. The positions, to be presented and argued, will be supported with field and operational data. Background The industry s perceived effects on drilling efficiency, when compared to actual field situations, highlights certain critical issues. Drilling efficiency is claimed to improve when increases, and asserted to deteriorate when declines. As a means towards drilling efficiency improvement, enhancing strategies are usually devised and implemented. However increases, even when the perceived effects on drilling efficiency are accepted, have not always had the desired results on operational costs. Consequently, increases cannot be assumed to always have positive effects on drilling efficiency. This realization exposes a weakness in the current vs. drilling efficiency relationship. Drilling efficiency will have the desired effects on costs when all the critical operational parameters are identified and analyzed. These parameters, referred to as performance qualifiers (PQ) 5 include the following footage drilled per BHA, downhole tool life, vibrations control, durability, steering efficiency, directional responsiveness,, borehole quality, etc. As part of the evaluation process, the PQs must be accorded their rightful levels of importance based on the defined project objectives.

2 2 IADC/SPE To improve drilling efficiency, the listed performance qualifiers should not be analyzed in isolation because they are inter-related. Consequently, maximization of any particular PQ, without identifying and addressing the effects the effort has on the other PQs, always compromises drilling efficiency 6,7. The earlier improvement efforts, often did not address these concerns. These observations explain s weak and inconsistent effects on drilling efficiency. It is not sufficient to merely expose s limitations. Rather, systematic processes that ensure complete understanding and effective evaluation of all PQs, must be developed. Rate of Penetration () is defined as advancement in unit time, while the drill bit is on bottom and drilling ahead. Although important, improvement must not compromise other PQs. Regardless of project type and/or drilling program, the PQs as listed earlier are always the same. However, the ranking and importance of the different PQs can vary for different projects, whether similar or not. Consequently, can have different ranking with regards to its effect on drilling efficiency. Most of the factors that affect (FA) have influencing effects on the other PQs. Based on the current discussion, these factors can be grouped into the following categories planning, environment, and execution. 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. belong to the planning group. Lithology types, formation drillability 8 (hardness, abrasiveness etc), pressure conditions (differential and hydrostatic), and deviation tendencies, etc. are the environmental factors. Weight-on-bit (WOB), RPM, drilling dynamics, etc. belong to the execution category. There are two main types of instantaneous ( i ) and average ( av ). As the name implies, instantaneous 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 is measured over the total interval drilled, by a respective BHA, from trip-inhole (TIH) to pull-out-of-hole (POOH). FA Effects on FA s elements usually have positive effects on instantaneous. However this benefit, depending on how it is achieved, as well as its duration, does not always guarantee improvements in average. In addition to possibly having a direct negative effect on average (Figure 1), FA can also have an in-direct effect on average based on its effects on the other PQs (will be discussed later). A Constants same hole size same formation same drilling system B B A Figure 1: Diagram showing possible effects of WOB on. Well A (green line), with less WOB, drilled slower (initially) but stayed consistent to TD. Well B (red lined), with more WOB, drilled faster (initially) but required a BHA trip for a bit change.

3 IADC/SPE In all discussions and evaluations, aimed at improving drilling efficiency, the emphasis must always be placed on average. FA vs. Average : The understanding and application of FA, in order to achieve its desired effects, is very subjective. This issue sometimes creates misinterpretations, with regards to the effects and consequences of FAs elements. However, FA s effects on and drilling efficiency cannot be disputed. The most critical question that needs to be answered is, which is FA impacting, and what effect does that specific have on operational costs?. As an example, WOB when elevated usually increases instantaneous. However, drilling efficiency improvements are only dependent on average. As a result, the instantaneous achievement must be converted into average gains. To achieve this objective, the following questions must be answered: Was the drilling system design designed (bit, BHA, drive system) to allow for the WOB increase. Can the FA categories (planning, environment and execution) accommodate the gain Has an efficient action (WOB increase) vs. reaction ( gain) relationship been established Considering the footage to be drilled, as well as the vs. WOB relationship, will the drilling system get to the planned section TD or POOH depth. If any of the above questions is answered NO, then the gain, achieved with the WOB increase, will be short-lived with a mere instantaneous effect. In such instances, the secondary repercussions of the instantaneous gain end up negating the intended benefits. The increased instantaneous, by being short lived, leads to unplanned events (UE) or trips, to change out bits, other tools, or not being able to get casing to bottom or poor cement jobs. improvement, to have the desired effect, must be sustainable over the planned interval that is to be drilled. Although the discussion has focused on the WOB effect, the same arguments will be valid for most of FA s elements. Even when the higher instantaneous is sustainable, leading to improved average values, the enhanced will still not guarantee drilling efficiency improvements. Drilling Efficiency Cost Per Foot, Mechanical Specific Energy, and Feet per Day Effects As mentioned earlier, attempts to quantify drilling efficiency tied it to cost per foot (CPF), mechanical specific energy (MSE), and feet per day (FPD). Equations (1, 2 and 3) identify the parameters that influence CPF, MSE, and FPD respectively. 1 BC Tt CPF = [( ) + RR (1+ ) ] t t... ( eq. 1) MSE = WOB π RPM T A AB B... (eq.2) FPD = i 24...( eq.3 ) As presented, the equations depend strongly on. Figures (2 and 3) track s influence on drilling efficiency, through CPF. Likewise Figures (4 and 5), as well as Figure (6 and 7), track s effects on drilling efficiency through MSE and FPD respectively. These associations, as discussed earlier, are not valid. MSE and CPF reductions, whereas necessary, are not sufficient when it comes to achieving drilling efficiency. The same is true for FDP increases.

4 4 IADC/SPE CPF 2 Drilling Efficiency 3 1 CPF Figure 2 Figure 3 Figures 2 and 3: Perceived effect of on drilling efficiency, tracked through cost per foot (CPF) 4 MSE 2 Drilling Efficiency 3 1 Figure 4 MSE Figure 5 Figures 4 and 5: Perceived effect of on drilling efficiency, tracked through mechanical specific energy (MSE) 2 4 FPD 1 Drilling Efficiency 3 FPD Figure 6 Figure 7 Figures 6 and 7: Perceived effect of on drilling efficiency, tracked through feet per day (FPD)

5 IADC/SPE Drilling Efficiency Definition To achieve drilling efficiency, certain basic requirements and conditions must be met. The primary objective must be geared towards the lowest cost per section and ultimately the construction of useable wells. In this regard the sources of non-productive time (NPT) visible (VLT) and invisible (ILT), must be analyzed in detail. Considering this paper s central theme, this commitment must ensure minimization of drilling related inefficiencies (ILT). In addition, certain drilling related unplanned events (UE), which fall into the VLT category, especially trips associated with bits, BHAs, downhole tools, and drive systems, must also be analyzed. In order to move the discussion forward, the ILT and UE elements will be referred to as factors that affect drilling efficiency (FADE). The relationships, and contributions of FADE, must be clearly understood, in order to achieve drilling efficiency and drive down operational costs. As a first step, drilling efficiency will now be defined as the construction and delivery of a useable well, while achieving the operational conditions needed to achieve the lowest cost imprint. As part of this discussion, it is worth noting that the PQ elements belong to the FADE group (Figure 8). Invisible Lost Time (ILT) Unplanned Events (UE) Performance Qualifiers (PQ) Figure 8: Diagram showing factors affecting drilling efficiency (FADE), including Performance Qualifiers (PQ) Drilling Efficiency FA and PQ Effects As noted in the definition for drilling efficiency, there is no specific mention of. However there is a requirement to achieve a reduced cost imprint, which is where the previously listed PQ elements come in. What is worth noting is that FAs elements influence all the different PQs. In addition, all the PQs are inter-related (Figure 9). These realizations, in addition to forcing a re-evaluation of the mechanical and operational influences, also govern how drilling efficiency is viewed and achieved. Footage Downhole tool life Durability Vibrations Control Directional Responsiveness Borehole Verticality & Quality Steering Efficiency Figure 9: Diagram showing inter-relationships between performance qualifiers (PQ). FAs elements can also have indirect effects on. This is evident, when the FA discussion is expanded to cover all the different PQs.

6 6 IADC/SPE As an example, increased RPM usually leads to instantaneous improvements in. This action and associated gain, could also lead to the initiation of vibrations 9,10, depending on the bit type, BHA design, formation types, other operational parameters, and well profile. The vibrations could end up causing impact damage 11 to the drill bit, which then sacrifices bit durability 12. Due to the induced impact damage (Figure 10), becomes compromised (Figure 11). It is worth noting that impact damage and durability are not the same. However, impact damage reduces durability. Figure 10: PDC bit with compromised durability, as a result of impact damage sustained from bit vibrations. Impact Damage Figure 11: Effect of impact damage on In this example, the intended gain from the RPM increase was in-directly compromised due to the associated impact damage. Although RPM was used in this example, most of the FA and PQ elements, when paired for similar discussions, will yield comparable results. As an example, WOB borehole verticality can be substituted for RPM and durability respectively. In addition to the FA 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 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 when compared to. If the conditions needed to improve create negative effects on other PQs, the gain will NOT improve drilling efficiency.

7 IADC/SPE As an example improvement in a long tangent section, achieved at the expense of directional responsiveness or steering capability, will not improve drilling efficiency. Likewise, improvements achieved at the expense of bit durability or borehole verticality will also not improve drilling efficiency. Regardless of application or project type, achievement of operational objectives (defined by the PQs) must always outweigh the mechanical considerations (established by MSE and ). Such a strategy will always improve drilling efficiency. In addition, the mechanical considerations must be evaluated as part of the PQ discussion, because is one of several PQs. As presented and argued, and drilling efficiency are not the same. Maximization of instantaneous is easy, but that is not the real issue. Achievement of pre-determined 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 to 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 (Equation 4). Planned Spend( AFE ) VC = 100 Actual Spend( AS )... (eq.4) 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 some dysfunctions/flounders. As is well known, exploration wells present different challenges. Limited and/or unreliable data, based on assumptions and types of risk models used, usually complicates AFE determinations. In addition, unknowns associated with the drilling environment can also obscure this issue. Consequently initial AFEs can sometimes 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, the 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 the unique challenges and unknowns, may still have unpredictable planned spends (AFE), regardless of well count. Drilling efficiency s impact on value creation is more accurate when measured in a consistent AFE zone (Figure 12). The 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 ranking also changes for similar projects. Zone A Zone B Expenditures AS AFE Time on Drilling Program Figure 12: Time on drilling program s (TDP) effects on expenditures planned (AFE) and actual (AS). The two zones of interest (A and B), representing high and flat AFE, are also shown

8 8 IADC/SPE As an example, may go from being least 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 finally captures the highest priority, and project objectives are being met, still has to be improved from project to project in order to continuously create value. Any other PQ, when substituted for 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, and 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 detail review of the action vs. 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 (Figure 13). On Bottom Time (OBT) Non-Production Time (NPT) Planning and System Design (PSD) Figure 13: Diagram showing planning and system design (PSD) effect on Non-Productive Time (NPT), tracked through On-Bottom-Time (OBT) As a result, all FADE and drilling NPT factors associated directly or in-directly with NOT achieving the PQs or overall section goals, will be classified as drilling non-productive time (NPT D ). 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 commencing to pick 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 NPT D. TDT = OBT + NPT... ( eq.5 ) 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 NPT D 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. In addition, 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 14).

9 IADC/SPE TDT Time Distribution NPT OBT Time on Drilling Program (TDP) Figure 14: Expected time on drilling program (TDP) effects on time distribution, as a result of drilling efficiency improvements. Drilling efficiency gains, accompanied with drastic reductions in operational costs, are achieved when OBT grows and NPT (specifically NPT D ) decreases. The OBT gain should not be seen as a reduction in, 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 of the projects, on which the principles were applied, will be discussed in this section. The two examples are intended to address different parts of the argument, as presented in this paper. Field Case A Drilling Efficiency Vs. (Mid-Continent, USA): Drilling data for two 8-1/2 sections, drilled in the same field and through the same formations (Wells A and B), are compared in this example. On Well A, a single BHA drilled 6681ft to section TD at an average of 98fph. 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 5452ft at 89.4fph and 479ft at 14.5fph 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. It is worth mentioning that identical 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. In addition, the relationships between the ranked PQs were also analyzed for their indirect effects. For Well B, the strategy was to achieve drilling efficiency through maximization by increasing WOB. The average WOB values, used on Well A and the first run on Well B, were 10klb and 16klb respectively. As can be seen (Figure 15), the initial s were higher on Well B, as will be predicted. However, and as discussed earlier, WOB s complete effect on was not addressed (note four questions that must be answered in all instances). In addition, s inter-dependencies 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 gain could not be converted into an increased average. The dull conditions of the identical bits used on the two runs are shown in (Figure 16). Subsequent wells drilled on this campaign, following the strategies discussed in this paper, achieved results that were similar to that realized on Well A. Total savings, for this hole size exceeded 300K USD.

10 10 IADC/SPE Figure 15: Offset rock mechanics analysis data and drilling parameter plots showing WOB differences and trends for Wells A (red trace) and B (blue trace). Well A Well B Figure 16: Dull conditions of same type bit (different serial numbers) used on Well A (left) and Well B (right). Field Case B as Dominant PQ (West Africa): This project focused on an 8-1/2 interval on the West Coast of Africa. In its execution, the project followed the principles discussed in this paper. After evaluations of the offset data, and identification of the relevant performance qualifiers, was deemed the most critical. FAs effects, as well as the inter-relationships between the other PQs were also analyzed. Even though more footage was drilled in the same hole section, on the other wells (in comparison to the offset), the improvements were achieved without compromising the other PQs. The achieved improvements, and the footages drilled, as compared to the initial benchmark, are shown in (Table 1). In addition, the dull conditions of two of the bits used on the drilling campaign are shown in (Figure 17). In all situations, FA s elements met the four conditions identified earlier. In addition, PQ analysis and re-ranking (outside of, 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 3.9MM USD.

11 IADC/SPE Footage Drilled Rate of Penetration Footage Well A Well B Well C Well D Table 1: Well Name Comparison of (main PQ) and footage achieved on drilling campaign to that of initial benchmark (Well A) West Africa Project Figure 17: Dull conditions of two of the bits used on the West Africa drilling program

12 12 IADC/SPE Conclusions Most of the industry s performance quantifying metrics are strongly dependent on (Instantaneous and Average). Factors affecting (FA) can have direct negative effects on, if certain conditions are not met. Drilling Efficiency and are not the same. Their effects on operational costs reductions are different. is one of several performance qualifiers (PQ), and not the ONLY factor that influences overall section or well drilling efficiency. PQs are inter-dependent, and must be analyzed in unison. FA elements have indirect effects on, due to PQ interdependencies. 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. Acknowledgement 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 in this paper. Special mention also goes to Bill Thornburg and the entire Transocean Discoverer Deep Seas drilling operations team. Nomenclature - Rate of Penetration i - Instantaneous Rate of Penetration av - Average Rate of Penetration CPF - Cost Per Foot FPD - Feet per Day MSE - Mechanical Specific Energy PQ - Performance Qualifiers BHA - Bottom Hole Assembly FA - Factors Affecting PDM - Positive Displacement Motor RST - Rotary Steerable Tool WOB - Weight on Bit RPM - Revolutions per Minute TIH - Trip in Hole POOH - Pull Out of Hole UE - Unplanned Events NPT - Non Productive Time VLT - Visible Lost Time ILT - Invisible Lost Time FADE - Factors Affecting Drilling Efficiency VC - Value Creation AFE - Approval for Expenditure AS - Actual Spend BC - Bit Cost H - Footage Drilled Tt - Round Trip Time RR - Rig Rate A B - Area of drill bit T - Torque TDT - Total Drilling Time TDP - Time on Drilling Program NPT D - Drilling related NPT TD - Total Depth

13 IADC/SPE References 1. Taylor, M. R., Murdock, A. D., Evans, S. M.: High Penetration Rates and Extended Bit Life Through Revolutionary Hydraulic and Mechanical Design in PDC Bit Development SPE 36435, October Sinor, L. A., Powers, J. R., Warren, T. M.: The Effect of PDC Cutter Density, Back Rake, Size, and Speed on Performance SPE/IADC 39306, March Dupriest, F. E., Koederitz, L.: Maximizing Drill Rates With Real-Time Surveillance of Mechanical Specific Energy SPE/IADC 92194, February Pessier, R. C., Fear, M. J.: Quantifying Common Drilling Problems With Mechanical Specific Energy and a Bit Coefficient of Sliding Friction SPE 24584, October Mensa-Wilmot, G., Southland, S., Mays, P., Dumrongthai, P., Hawkins, D.: Performance Drilling Definition, Benchmarking, Performance Qualifiers, Efficiency and Value SPE/IADC , March Weaver, G. E., Clayton, R. I.: A New PDC Cutting Structure Improves Bit Stabilization and Extends Application into Harder Rock Types SPE/IADC 25734, February Mensa-Wilmot, G., Krepp, T.: Innovative Cutting Structure Improves Stability and Penetration Rate of PDC Bits Without Compromising Durability SPE/IADC Mensa-Wilmot, G., Calhoun, B., Perrin, V. P.: Formation Drillability Definition, Quantification, and Contributions to Bit Performance Evaluation SPE/IADC 57558, November Cooley, C. H., Pastusek, P. F., Sinor, L. A. The Design and Testing of Anti-Whirl Bits SPE 24586, October Fear, M. J., Abassian, F., Parfitt, S. H. L., McClean, A.: The Destruction of PDC Bits by Severe Slip-Stick Vibration SPE/IADC 37639, March Cooley, C. H., Meany, N.: The Development of a Fracture Resistant PDC Cutting Element SPE 28312, September Mensa-Wilmot, G., Calhoun, B.: PDC Bit Durability Defining the Requirements, Vibration Effects, Optimization Medium, Drilling Efficiencies and Influences of Formation Drillability SPE 63249, October 2000