SUBSURFACETips of the Month

2019

Table of Contents

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How Project GovernanceAffects Decision Making

Introduction to Directional Drilling

Prospect and Play Assessment: Volumetric Analysis

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Table of Contents

Get the Most Out of a PetroSkills Course

Geostatistical Approachesto Prospect Risk

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HOW PROJECT GOVERNANCE AFFECTS DECISION MAKING

As a project manager, you will be challenged to make many significant decisions in your career. Whether you are an early career project manager or senior project manager, it pays to understand how project decisions are made. All projects have a governance structure that guides project decision-making. Some questions you may come across are as simple as, “Do you have the authority to make a certain decision?” Others are more challenging, such as, “Will the implementation of a decision add to or reduce project value?”This article discusses petroleum industry governance practices and procedures that will help you answer the following:

► Who are the decision-makers and decision influencers?► What is the project and organization decision structure (pathway)?► How is risk controlled through delegation of authority?► How is risk controlled through delegation of authority?► How is decision-making is guided by project processes, standards, procedures and guidelines?The figure below exhibits the components of governance that are critical in project decision making.

Published January 2019

Written by: Ken Lunsford

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GOVERNANCE: STAKEHOLDERSMore than ever, project decisions have far-reaching impacts on the environment, local cultures, nearby communities and regional infrastructure. Government requirements for studies, permits and information

have never been greater. Effective stakeholder management is necessary to meet these requirements and achieve successful project outcomes. The types of stakeholders you will need to manage are:

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Internal Stakeholders Approved members of the project program who have a formal, official, or contractual relationship with the organization.

External Stakeholders Not formal members of the project development, but may affect or be affected by the project.

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As you can see, there are a lot of people and groups who want to be a part of decisions that are made on a project. Very large, complex projects attract more interest than smaller facility upgrade projects. In either case, those who have 1) authority to review a decision recommendation or 2) the authority to decide, must be clearly identified.For more insight on how to manage project stakeholders, read How to Effectively Manage Project Stakeholders.

GOVERNANCE: ADVISORY COMMITTEES AND SUBJECT MATTER EXPERTSThe Project Decision Board or Decision Maker relies to a large extent on others to ensure that recommendations that come before him have been carefully vetted by qualified specialists or subject

matter experts. These experts are often organized into committees or networks that are a part of a project’s governance structure. The committee structure for an international oil and gas mega project with multiple partners can be complex. See the figure below.The terms of reference (purpose, structure, roles and responsibilities) for the Management Committee are specified in a Production Sharing Agreement (PSA). The terms of reference of the Operating Committee are specified in a Joint Operating Agreement.As expected, the speed at which decision are made in a complex governance structure, such as shown above, can be very slow. Often recommendations are returned after committee and support review with numerous questions. A major decision will have to go through 2-3 reviews and OpCom and ManCom approvals.

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The governance structure for facility enhancement projects is smaller and less complex. See the figure above.Decision making on medium sized projects is faster. Approvals for purchase a piece of major equipment or contracting of engineering services that require regional BU Manager sign-off can easily take 6-8 weeks. Adequate approval time must be included in the project execution schedule.

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GOVERNANCE: DELEGATION OF AUTHORITYThe degree to which approval authority is delegated varies by company, culture and ownership. The figure below shows typical delegation levels for a business unit.Some companies delegate little approval authority to project managers believing that the best decisions will be made 1) after multiple reviews and 2) when their best decision makers (which are at the higher levels in accompany) make the call. This practice often leads to schedule delays due to the multiple reviews at each level and the challenge of getting on the upper-level manager’s schedule.

GOVERNANCE: ROLES AND RESPONSIBILITIESClear roles and responsibility facilitate good decision making. These roles and responsibilities are generally defined in two documents. These documents are the RACI diagram and job description. The RACI diagram spells out who is responsible and accountable along with who should be consulted and/or informed when recommendations for key project decisions are being formulated and vetted. Further detail on responsibilities and accountability can be found in individual job descriptions. A good practice for onboarding is to have the new team member review and agree to the job description before beginning their new role.

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GOVERNANCE: PROJECT MANAGEMENT SYSTEMS, PLANS AND PROCEDURES

Document Hierarchy

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With such an array of guidance and instruction, why do 70% of today’s major industrial projects fail by overrunning cost, exceeding the schedule, and exhibiting poor operability? The story is only a little better for smaller projects whose failure rate is about 30%. Project failure is typically attributed to:

► Inadequate definition

► Wrong project selected

► Poor execution

► Extended startup

However, ineffective project governance is also a root cause of project failure. Some examples of ineffective governance are:► Smaller projects are burdened by governance structures that are designed for larger, more complex projects. The administrative burden of “checking all boxes” is excessive. Decision making is slow.

► Project processes focus more on reporting needs rather than effective decision making.

►Large projects may suffer from risk av ersion due to the high economic and career penalty that can come from poor decisions. Requiring group consensus on major decisions blurs individual accountability. Risk aversion often leads

to recycling of approval documents due to questions and requested changes at each level, and decisions being influenced by those who do not have a direct stake in the project.

CONCLUSIONTimely, effective decision making is required to maintain project progress and produce good cost and operability outcomes. Understanding a project’s governance structure and the requirements for gaining approvals is essential for good project management. Governance structures and the accompanying resources and processes must be tuned to match the risk, size and complexity of a project. Clear roles, responsibilities and accountability for internal project stakeholders are critical. Otherwise, we have no one to blame but ourselves.To learn more about project governance, decision making and other key focus areas we recommend enrolling in Project Management for Engineering and Construction. Additionally, you can browse all our project management courses.

Related articles:How to Effectively Manage Project StakeholdersWhy Do Projects Fail?Delivering Bad News to Stakeholders and Decision Makers

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INTRODUCTION TO DIRECTIONAL DRILLING

Published March 2019

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This post contains material from DHD(Directional, Horizontal, and Multilateral Drilling) and BDT(Basic Drilling Technology). At one time, it was assumed all oil wells were essentially vertical or the bottom of the hole was directly under the drilling rig. The petroleum industry did not become fully aware of deviated well problems until the development of the Seminole, Oklahoma field. The wells in this field were drilled very close together and as a result wells were drilling into one another, and ones which were already producing. Deviations as high as 46º from vertical were measured in the Seminole wells. The average deviation from vertical was approximately 13°. Directional drilling began emerging in the late 1920's when curvey instruments were developed that could measure both inclination and azimuth.The first controlled directional well was drilled in California in 1930 to tap offshore oil reserves. Unfortunately, operators were drilling across lease

lines in order to drain oil owned by another individual, resulting in legal problems. In the 1930's, wells were directionally drilled to tap oil reserves that would otherwise be inaccessible. In one case, directional drilling was employed to produce oil from under a cemetery. Oil was produced from under the ocean by placing the rig on the shore and directionally drilling into the offshore oil deposits.Little attention was paid to directional drilling until a relief well was drilled to kill a blowout near Conroe, Texas. The relief well was drilled near the surface location of the blowout. Directional drilling techniques were used to intersect the producing formation near the blowout, and the blowout was killed by pumping fluid down the relief well and into the blowout well. Since then, directional drilling has been widely accepted. Today, the on-going research and development of new tools and techniques are making directional drilling more accurate and economical.

Fig. 1 Examples of directional drilling situations.

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Directional drilling is now common from platform and offshore locations. The expense of placing production equipment off shore, or in the arctic, requires that wells be produced into a common area. The well heads can be located on one platform instead of several if wells are drilled directionally from one location. The drainage area for a platform may be extended with extended reach drilling (ERD) so that fewer wells and platforms may be needed. This will also minimize the environmental impact of the operations and maximize the economics of hydrocarbon production.Platforms such as the one shown below may be taller than the tallest buildings in the world. Most of the structure will be below sea level and not visible. These platforms may be larger than three football fields. The structural loading is crucial to the cost of these tall structures. Each ton of material on the decks will add significantly to the costs, so space is at a premium. However, the cost of a structure this big makes it imperative that as many wells as possible be drilled from this one location. Directional drilling has permitted development of many subsea production intervals in an economic manner even though these platforms are expensive. The investment for these platforms, before a single drop of oil or cubic foot of gas is produced, is frequently in the hundreds of millions or billions of US dollars. Every effort is made to decrease drilling costs for these production platforms.

HORIZONTAL DRILLINGHorizontal drilling is an important application of directional drilling and is used to increase the productivity of various formations (Figure 3). One of the first applications for horizontal drilling was in vertically fractured reservoirs. In fractured reservoirs, a significant quantity of the production comes from fractures. Unless a vertical well encounters a fracture system, production rates will be low. A horizontal well has a much greater chance of encountering a prolific fracture system. Horizontal wells are a very common way to produce formations. The Austin Chalk in Texas is a classic example of using horizontal drilling techniques to produce a fractured reservoir.

Fig. 2 Example of a platform drilling operation.

Fig. 1 Examples of directional drilling situations.

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Fig. 3 Horizontal drilling.

Horizontal drilling is used to produce in thin oil zones with water or gas coning problems. The horizontal well is optimally placed in the oil leg of the reservoir. The oil can then be produced at high rates with much less pressure drawdown because of the amount of formation exposed to the wellbore.Additionally, horizontal wells are used to increase productivity from low

permeability reservoirs by increasing the amount of formation exposed to the wellbore. Numerous hydraulic fractures can be placed along a single wellbore to increase production and reduce the number of vertical wells required to drain the reservoir.Horizontal wells can also be used to maximize production from reservoirs which are not being efficiently drained by vertical wells. These wells usually

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have permeability streaks in combination with natural fractures. The horizontal well can connect the portions of the reservoir that are productive.

Horizontal drilling was a major innovation in the industry. It revolutionized shale drilling and led to the technique of fracking. Some believe that fracking "obscured the far more important role played by horizontal drilling in enabling oil and gas to be produced from previously inaccessible rock formations, revolutionizing energy output and even international relations". Today approximately two-thirds of all wells are horizontal. [1]

MULTILATERAL DRILLINGDirectional drilling can be used to drill multilateral wells as well. Multilaterals are additional wells drilled from a parent wellbore as illustrated in Figure 4. Multilaterals can be as simple as an open hole sidetrack or it can be more complicated with a junction that is cased and has pressure isolation and reentry capabilities. Multilaterals are used where production can be incrementally increased with less capital costs. Multilaterals can be used offshore where the number of slots are limited. It is also used to place additional horizontal wells in a reservoir.

Fig. 4 Multilateral wells drilled from a platform.

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SIDETRACKINGSidetracking is one of the primary uses for directional drilling. Sidetracking is an operation which deflects the borehole by starting a new hole at any point above the bottom of the old hole as in Figure 5. The primary reason for sidetracking is to bypass a fish which has been lost in the hole; however, there are several other reasons for sidetracking. A sidetrack can be performed so the bottom of the hole can intersect a producing formation at a more favorable position such as up dip above the oil-water contact. A well can be sidetracked to alleviate problems associated with water or gas coning. A sidetrack can be performed in an old well to move the location of the bottom of the hole from a depleted portion of the reservoir to a portion that is productive, such as, across a fault or permeability barrier. Sidetracking an exploration well can lead to a better geologic understanding of an area (Figure 6) especially where the geology is complicated. Sidetracking and directional drilling can be more economical than multiple exploration wells if the upper portion of the well is expensive to drill.In horizontal wells, it is a common practice to sidetrack existing vertical wells. A whip stock is set inside the casing and the well sidetracked. Then the formation is drilled horizontally to increase productivity. Multiple sidetracks can be drilled from the same well, which are termed multilaterals.Most often, a sidetrack is accomplished by setting a cement plug in the hole and dressing off the plug to a depth at which the sidetrack will commence.

The sidetrack can be either "blind" or "oriented". In a blind sidetrack, the direction of the sidetrack is not specified and is not considered a directional well. In either case, a deflecting tool is used to drill out the old hole and start a new hole.

Fig. 5 Sidetracking a stuck bottomhole assembly.

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Fig. 6 Multiple sidetracks.

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STRAIGHT HOLE DRILLINGIn some areas of the world, deviation from vertical is caused by the natural formation tendencies. Packed hole assemblies are employed to keep the dogleg severity within reason. Pendulum assemblies are used to keep the inclination as low as possible though with limited success at lower inclinations. If the inclination is already too great to hit a previously specified target, pendulum assemblies, and sometimes downhole motors are used to bring the hole back within range of the target. It should be noted here that sometimes targets are unduly restricted. Controlling the inclination of a well costs significantly more than letting it deviate and keeping the dogleg severity within reason. If there are no restrictions on bottomhole location, the well should be allowed to deviate.

CONTROLLED DRILLINGControlled directional drilling is used when drilling multiple wells from an artificial structure such as offshore platforms, drilling pads, or man-made islands (Figure 8). The economics of building one offshore platform for each well would be prohibitive in most cases. However, since wells can be directionally drilled, forty or more wells can be drilled from a single platform. Without controlled directional drilling, most offshore drilling would not be economical. Some fields are developed using drilling pads where multiple wells are drilled from one location due to economic or environmental pressures. Where the environment is concerned, roads and production facilities may not be allowed for each surface location with a vertical well. As oil companies become more environmentally conscious, it may be politically advantageous to develop fields from drilling pads in sensitive areas. In areas of shallow water depth, multiple wells can be drilled from artificial islands. Subsea wells are drilled from a template on the ocean floor. In all cases, location construction expenses and rig move expenses are reduced. Also, due to the proximity of the wells, production costs are lower. However, for most land wells, it is usually more economical to drill vertical wells rather than drill directional wells from a pad.

Fig. 7 Straight hole drilling.

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SEALED SAND ZONES DRILLINGThere are special cases when multiple sands are drilled with a single wellbore. This occurs when steeply dipping sand zones are sealed by an unconformity, fault, or salt dome overhang. Several vertical wells would be required to produce each sand, which are separated by a permeability barrier. However, all the sand zones can be penetrated with one directionally drilled well thereby greatly reducing the cost of production (Figure 9).

Fig. 8 Multiple wells from an artificial structure.

Fig. 9 Drilling multiple sands from a single wellbore.

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REACHING INACCESSIBLE DEPOSITS There are times when oil deposits lie under inaccessible locations such as towns, rivers, shorelines, mountains, or even production facilities (Figure 10). When a location cannot be constructed directly above the producing formation, the wellbore can be horizontally displaced by directional drilling. This allows production of an otherwise inaccessible hydrocarbon deposit.

FAULT DRILLINGDirectional drilling is also applicable in fault drilling (Figure 11). It is sometimes difficult to drill a vertical well in a steeply dipping, inclined fault plane. Often, the bit will deflect when passing through the fault plane, and sometimes the bit will follow the fault plane. To avoid the problem, the well can be drilled on the upthrown or downthrown side of the fault and deflected into the producing formation. The bit will cross the fault at enough of an angle where the direction of the bit cannot change to follow the fault.

Fig. 10 Inaccessible location.

Fig. 11 Fault drilling.

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SALT DOME DRILLING Many oil fields are associated with the intrusion of salt domes. Directional drilling has been used to tap some of the oil which has been trapped by the intrusion of the salt. Instead of drilling through the salt overhangs, the wells can be directionally drilled adjacent to the salt dome and into the underlying traps as shown in Figure 12. However, since the development of salt saturated and oil based muds, the amount of directional drilling has decreased. It is difficult to drill long intervals of salt with fresh water muds. Directionally drilling around the salt, alleviates a lot of the problems associated with drilling salt.

RELIEF WELL DRILLINGA highly-specialized application for directional drilling is the relief well. If a well blows out and is no longer accessible from the surface, then a relief well is drilled to intersect the uncontrolled well near the bottom (Figure 13). Water or mud is then pumped through the relief well and into the uncontrolled well. Since it is sometimes required that the relief well intersect the uncontrolled well, the directional drilling must be extremely precise and requires special tools. Survey data is not accurate enough to intersect a wellbore at depth; rather, proximity logging is required when drilling relief wells.

Fig. 12 Salt Dome drilling. Fig. 13 Relief well drilling.

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EXTENDED REACH DRILLINGAnother application of directional drilling is what is commonly termed as extended reach drilling. As illustrated in Figure 14, extended reach drilling is where wells have high inclinations and large horizontal displacements for the true vertical depth drilled. It is used to develop reservoirs with fewer platforms or smaller sections of a reservoir where an additional platform cannot be economically justified. Extended reach drilling will become more popular as the costs of platforms in deeper water and severe environments become more expensive.

Fig. 14 Extended reach drilling.

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Advances in technology have allowed operators to drill extended reach wells with very high HD/TVD ratios (the ratio of the horizontal displacement to true vertical depth). Wells have been drilled with HD/TVD ratios in excess of 6/1 as illustrated in Figure 15. In these wells, the horizontal departure was more than six times the true vertical depth with the total measured depth exceeding 32,800 feet (10,000 m).

Fig. 15 Extended reach wells drilled by BP.

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One of the most important benefits of directional drilling is the total well cost per equivalent barrel of oil is greatly reduced. If a field extends over a large geographic area, several platforms might be required to produce the hydrocarbons. Eliminating just one platform will have a several million dollar impact on development costs. Hydrocarbons from the fringe areas of the reservoir or in remote fault blocks may also be economically produced by directionally drilling from an existing platform. These additional reserves will extend the life of existing platforms or pad locations. Frequently, in the arctic or in swamp country, drilling locations are so expensive that rigs are positioned on pads. In California, for example, many wells south of Los Angeles are drilled from land westward under the sea. Some platforms are positioned in relatively shallow water and directionally drill under deeper water. On land, directional wells are so inexpensive now that wells are drilled under forests or trees to avoid compensating the landowner for cutting down trees.

Directional drilling does require a higher level of technology than is normally associated with straight hole drilling. Equipment must be available to determine the direction and angle of the hole. Usually, this means that some telemetry devices must be installed in the BHA. One problem with directional wells is a frequent change in direction

– either vertically or horizontally. Too many changes in the vertical direction can result in the wellbore penetrating the top or bottom shale, penetrating a gas cap, or penetrating a water leg. There is also a problem in severe cases of pulling the BHA back through the wellbore. A directional driller is added to the rig crew to supervise interpretation of data received from the BHA and make adjustments to keep the well on track and prevent too many doglegs in the well. The rig crew and drillers need additional training to drill without unexpected problems. The wells are much more difficult to plan and require expertise to properly engineer the program and well path. With expensive equipment in the hole, stuck pipe and other problems are much more expensive. The equipment rental for telemetry and directional driller expenses increase the daily rig costs. Downtime or time not spent drilling must be minimized to achieve economic benefits from directional drilling.

To learn more about directional drilling, we recommend enrolling in our Directional, Horizontal, and Multilateral Drilling course.

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References[1] Kemp, John. (14 July, 2014). The real shale revolution: Kemp. Reuters. Retrieved from http://www.reuters.com/article/us-shale-usa-kemp-idUSKBN0FJ26220140714

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PROSPECT AND PLAY ASSESSMENT: VOLUMETRIC ANALYSIS

Published May 2019

Written by: Jeffrey Aldrich

This technical series is designed to offer working professionals, their coworkers and management a thorough understanding of the fundamentals of assessing oil and gas resources.

Assessment of prospects and plays requires two types of analysis:

1. How much hydrocarbons may be present = Volumetric Analysis

► Range of potential resources► Most likely resource amount

2. What is the likelihood of an economic field being present = Risk Assessment

► What is the probability?

This article focuses on assessing hydrocarbons contained in individual prospects and leads through volumetric analysis. Volumetric analysis is a key part of assessment because it helps determine the amount of oil or gas that may be present and gives a range of expected resources. The techniques offered are compiled from reviews of techniques used around the world. The basic objective is to equip explorationists with the most modern and well-considered approaches to solving the business problems of finding new exploratory resources. Part two

of the series will focus on the RISK ASSESSMENT.

DEFINING SUCCESSThe value and interpretation of any assessment is based on how success is defined in the analysis. It is important that all parties involved know the standards by which the assessment was conducted. Therefore, the key consideration is defining the meaning of success in the probability analysis.The definition of “success” can differ across the industry but needs to be consistent within the corporation. The minimum economic approach is the method supported by many companies and is the basis of our Prospect and Play Assessment course; however, all methods are covered.Others in the Industry recommend alternate methods, typically assessing “geologic success” first and subsequently completing the risk assessment of economic viability later in a second analysis.

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THE KEY QUESTION FOR ANY EXPLORATORY ASSESSMENTHow much oil and gas may be present? = Average expected amount= Range of reserves expected= VOLUMETRIC ANALYSIS

VOLUMETRIC ANALYSIS OF PROSPECTSThe recommended method for determining how much oil and gas may be present in a prospect is the combination of trap volumetrics and hydrocarbon charge. Ideally, we could map a single volume size, but this is typically unrealistic due to uncertainties for many of the volumetric factors. Uncertainty is a natural fact and normally a unique answer is not the favored solution. Typically, it is best to display the range of all potential sizes using an assessment curve and stochastic modeling.

STEP 1: Define Minimum Economic Size► Define the minimum field size determined to be economic in play► Interactive process in a company► Factors to be considered: • Oil and gas prices expected • Development costs • Infrastructure costs

• Production costs • Production timing • Corporate economic threshold • Discount rate

STEP 2: Select Ranges for Individual FactorsThe heart of exploration is gathering data that defines a prospect or play. Most of the time spent in exploration is expended data gathering, data interpretation and mapping. Assessment is most often the last step in the process before the decision to drill. As stated previously, the expected size of an accumulation is one of the two key questions that we need to solve in assessing a prospect or play. The challenge is to determine the size distribution of all legitimate potential hydrocarbon accumulation sizes that could be associated with any given prospect. To achieve this, an evaluation of the prospect volume elements must be completed. It is the explorationists’ responsibility to evaluate, set ranges for and assess all of the prospect volume elements utilized in the calculation of prospect volumetrics. As a review, the prospect volume elements are listed below.

Prospect Volume Elements► Trap volume • Reservoir thickness • Areal extent► Reservoir properties • Net/gross ratio

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• Average porosity • Average hydrocarbon saturation • Percent of trap-filled (hydrocarbon fill)

• Shrinkage or volume factor • Recovery factor

• Oil or gas fraction of hydrocarbon volume

Combining the prospect volume elements results in the following volumetric equations:

Hydrocarbons In Place = Gross bulk volume of trap x net/gross ratio x porosity x hydrocarbon saturation x hydrocarbon fill of trap volume

Recoverable Hydrocarbons At Surface = Hydrocarbons in place x shrinkage factor x recovery factor

Unconventional Reservoirs have similar but slightly different characteristics that must be taken into consideration.

Measures of UncertaintyUncertainty is inherent in the interpretation of prospect volume element values and must be addressed or captured.Typical workflow for explorationists is to map all of the critical geological factors. These factors may include but

are not limited to trap type, type size, reservoir presence, porosity, source capability, drive mechanism, seal, and recoverability. Subsequently, a range of values should be selected for each factor. It is imperative that the measures reflect local conditions as closely as possible, incorporating both specific individual values and known variations around each.Mapping of the prospect precedes the assessment and with modern 3D data sets, much of the inherent uncertainty has been reduced. PPA reviews more traditional assemblage of data so that the students can fully understand the principles behind the value prediction. Note that the approach to trap assessment is to predict total trap volume with no consideration of how much of the trap might be hydrocarbon filled. Hydrocarbon fill factor will be considered separately in a later calculation/prediction.Figure 1 is an example of a triangular range of reservoir thickness values related to a specific prospect. Based on the data presented, the thickness is expected to range between 25 feet and 75 feet with a mean thickness of 50 feet. The data presented reflects the most likely value (mean) and the range of uncertainty based on local knowledge.

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Before considering all of the individual prospect elements, let’s review the basics of how uncertainty can be portrayed. A key is to remember that though we normally describe the elements by a range of values, in reality, there is only one single true value that we are attempting to model. The problem is that we will never know what that value is until after we drill. That is why care must be used when determining values in the assessments.

Handling uncertainty - issues • Evaluators historically missed the range for 2/3 of the time • No difference for P30 and P90 ranges • People are prouder of their answers than data would indicate • Uncertainty ranges in are not expanded even when data indicates it should be so

Handling uncertainty – solutions • Understanding the objectives of the assessment • Better knowledge – better ranges

• Training in predictions • Lognormal or normal distribution for specific elements • Geostatistical refinement by single models or multiple simulations (probabilistic) • Assessing the Quantity of data vs the Quality of data

Fig. 1 Effective reservoir thickness

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Representative DataIt is critical in the assessment that proper specific and range of values are used in the analysis. Following is a quick overview of porosity and permeability and will be jointly considered since there are many dependencies between the two.

This analogue is much better data than we frequently have available in exploration – especially frontier exploration. Given the data, what permeability or range of permeability should be used in modeling?

Fig. 2 Multiple realizations of permeability

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Answer: P90 or Minimum is not the lowest seen value (4.72) but the value where 90% of the values are equal or greater to that value (6.0). The Mean is given as 10.32 and the Maximum as well should be where 10% of the values are equal or greater (not 24.12) but a bit lower (~19.0). This still gives a log normal distribution for permeability which is what is expected.

Fig. 3

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The illustration in Figure 3 offers ranges for porosity in several facies in an exploration play. Note the wide range in porosity for some facies compared to the narrow range for others. Compare the data presented here with that of Figure 2. Obviously, the strategy to represent porosity using these data will vary by the facies.

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Figure 4 is another depositional system in which the same point can be made as in the last illustration.The following table offers statistical measures from the data in Figure 4. This data would be very useful in modeling anticipated reservoir properties for an exploration play.

Fig. 4

Table 1.

Fig. 5 Uthmaniyah field, Saudi Arabia

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The data in Figure 5 is from the Ghawar area in Saudi Arabia, the world’s largest field. The left panels portray the porosity value ranges by facies and the right panels have permeability values.

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The illustration in Figure 6 above, from Ghawar, categorizes porosity and permeability data on a zone-by-zone basis demonstrating another way to illustrate reservoir properties.

Fig. 6

GENERATION OF AN ASSESSMENT CURVEVolumetric data is combined to create stochastic volumetric curves (an exceedance curve is shown below) which gives the range of possible volumes (Resource Volumes) on the X axis) and the Probability of those volumes on the Y axis.

Play Assessment by FieldsThe preferred methodology to estimate the hydrocarbon potential of a play is doing an assessment by fields or potential fields. To estimate play assessment by this approach, it is best to locate perceived areas of success first and then extend the analysis to the area of interest. This method is applied by explorationists who use past discovery-process data as guides but focus on future opportunities.

HOW MUCH RESERVE POTENTIAL IN PLAY?

This is the first assessment question

for a play. To answer the question a prediction must be made for the number of and size distribution of the potential fields.

Field Size DistributionsIt is important to tie the distribution to the largest anticipated field. Frequently we assess the largest prospect and use that as the anchor for the prediction. A caution here is to be confident that the field used is actually a part of the distribution and not an anomaly.

The data set should also be truncated on the small side. This allows the consideration of a manageable amount of data and focus on the most important part of the distribution; where most of the reserves are located. This also focuses efforts onto the economic portion of the size distribution with less distraction toward the small, uneconomic portion.

Field sizes are distributed log-normally as indicated intuitively and based on data from study of fields in trends around the world. This will be very useful in the construction of field size distribution predictions. It should be intuitive that there are many more small fields than there are large ones (Figure 8).

Baker et al (1986) demonstrate the field size distributions quite conclusively. Only 440, or 3% of the 13,985 fields in the United States are larger than 50 million barrels. Though these 440 fields represent only 3% of the fields, they comprise 80% of the reserves (Figure 9 and 10). It should be obvious from this data that the large fields are few, but very important in resource assessment.

Fig 7. Assessment Curve

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Fig 8. Distribution of oil fields

Fig. 9 Plotting representative prospect assessments

Fig. 10

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In the Baker et al paper, it was also shown that different plays have unique distributions (Figures 11 and 12). It is imperative that in any volumetric analysis that the proper distribution is employed. If an inappropriate data set is utilized the results could be disastrous.As a further demonstration of the lognormal distribution, fields in several plays have been plotted. Even though the shape of the distribution is unique to a play, each of these trends is lognormal.

Fig. 11

Fig. 12

SUMMARYCorrect volumetric assessment of both plays and of prospects involves the collection and analysis of large amounts of detailed information. For the prospect it means collecting and analyzing data on the source rocks, traps, seals, reservoirs, hydrocarbons and geologic history. In order to create prospects, the geoscientists must be able to extract detailed information from multiple sources and then extrapolate and creatively predict unseen and undrilled traps. Thus, in the area of new prospects, the data will be sparse and lacking in many respects and it requires special skills to accurately predict the range the potential hydrocarbon volumes that may be present and the most likely volume to be found. In play analysis, the geoscientists must gather information from all the existing fields and the existing prospects within the play fairway to accurately predict, on a portfolio basis, how many prospects are likely to be commercial, what is the range of sizes of the remaining prospects and where do the better prospect lie?Assessment of plays and prospects is an important tool in managing financial and human resources. To learn more about volumetric analysis and more we recommend enrolling in the upcoming session of Prospect and Play Assessment (PPA).

GEOSTATISTCAL APPROACHESTO PROSPECT RISK

Published June 2019

Written by: Jeffrey Aldrich44

A risk assessment is an estimate of the prospect chance of adequacy (probability) for sufficient hydrocarbon levels to meet or exceed the amount required for minimum economic accumulation. In this article, we will discuss geostatistical approaches for determining the probability of oil and gas in a prospect.In risk assessment, there are two key questions that must be answered for any exploratory assessment.

1. How much oil and gas may be present? – The Volumetric Analysis

2. What is the chance of commercial oil and gas being present? – The Risk Assessment

Last month’s Tip of the Month discussed volumetric analysis and how it is used to assess prospects and plays in our industry. This technical series is designed to equip explorationists with the most well-considered approaches to solving the business problems of finding new exploratory resources and a thorough understanding of the fundamentals of assessing oil and gas resources. The most crucial step in a risk assessment is to understand the geologic factors controlling oil and gas occurrences. These control factors, if inadequate or missing at the prospect or play being assessed, become the geologic risks that deny success.

Risking Terms – DefinitionsUncertainty: Uncertainty and risk are often used interchangeably in casual conversation. In this course, these terms are distinctly different. Uncertainty relates to measures, or most frequently estimates, of the size of a prospect or play volume factor. For example, in modelling the prospect, we can estimate the thickness of reservoir expected. The geological research might show that the prospective reservoir thickness might range from 20 meters to 35 meters in thickness; this is an expression of uncertainty. Probability: Probability is the chance that an event will occur. It is expressed as a predicted percentage occurrence of an event. It is important to understand that the events are

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mutually exclusive, only one will occur. As an example, we will either find more than 20 meters of reservoir or we will not. If the predicted probability of finding 20 meters of reservoir is 20% it means that as we have modelled the situation we will find in excess of 20 meters of reservoir 20 out of 100 times that we test these conditions. Risk: The probability of an event normally stated as a negative. Risk assessment must always relate to a standard and expressed as a measure of risk of a specific event (i.e. reservoir thickness)Chance of success: Explorationists focus on finding new reserves for the organization and, therefore, use a measure that predicts the positive side of the risk process. Chance of success expresses the probability of finding the critical play or prospect elements or the actual presence of the play or prospect itself. Chance of success is equal to 1 minus Risk. Chance of success may also be called probability of success or abbreviated as COS, COA or POS.

Describing Prospect RisksRisk must be identified against its alternative circumstance. In exploration, this most often refers to a probability of failure to achieve a predicted condition. If the condition is not defined properly, then risking is useless. Therefore, the first step in risking is to ask the question “risk of what”. This might, for example, be the risk of finding any reservoir rock or it might relate to some required minimum thickness of reservoir rock.It is very important to align the work and

activities of the explorationists with the business of the organization. Based on this, it is best to align the risk with the same critical business measures. Using the example of reservoir thickness from above, the best question might be “what is the risk of not having sufficient reservoir thickness for the prospect to be economic?”

RISK ASSESSMENTPrediction of probability of meeting minimum economic limit based upon the chance of success of the basic geologic controls:

• Sealed Trap• Reservoir• Source• Recoverability

CHANCE OF SUCCESSChance of success of a prospect or play is the product of the probabilities of the individual prospect elements. Each of these elements is judged against the amount of this factor required to reach the minimum economic reserves.► Chance of success of minimum economic accumulation not presence or absence► Used for individual factors and combined for entire accumulation► 1 minus Risk► Chance of success of prospect or play equals the product of individual geologic control factors

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• Sealed Trap• Reservoir• Source• Recoverability

BUILDING CONSISTENCY IN RISKINGIt is extremely important to establish a standard throughout the organization so that there is a consistent assessment standard by which to compare business options. This allows for a common platform for consideration of prospects generated on far-flung continents to be compared on a fairly even basis.An important aspect of risk assessment

is to convert the assessment that is most often expressed in qualitative terms into a quantitative measure. It is recommended that measures as shown above be applied across the organization to normalize these judgments.

Application of new geostatistical techniques and data acquisition methods will help improve quantitative estimates of risk, but the results will still be highly qualitative due to the fact that the real answer will never be known till after drilling occurs.

HOW TO MEASURE RISK► Establish a standard throughout the organization► Implement training that includes practice in making consistent assessments► Prospect post-mortems to define risking success and refine the process

RISK GUIDELINESThere are numerous “guides” for estimating the chance of success assessment values. Basically, all of the guides are qualitative. Though many guides today are automated and self-calculating, overall the input/rationalization is still qualitative. In short, there is no magic tool to automatically estimate/determine prospect risk. Chance of success assessment is still a humanistic endeavor.Immediately below are the chance of success guidelines taught in our Prospect and Play Assessment (PPA) course. These values are used for individual risk factors or combined for a prospect or play likelihood.

Geostatistical ApproachesCare should be taken when assigning values to each of the risk assessment factors. Assistance from other disciplines can provide better answers to provide an informed estimated value. Due to significant advances in geostatistical approaches, we have additional tools available. Quality of output from these approaches is directly proportionate to the quality of the geoscience input; it is important to remember the old computer mantra “garbage in, garbage out.”Modeling allows the geoscientist to predict reservoir occurrence in much more powerful ways than previously possible. The capability to offer multiple realizations of the reservoir with many options built into three-dimensional presentations bring capabilities that did not exist previously. Geostatistics lends itself to these multiple realizations allowing effective economic analysis. Geostatistics also serves as an excellent mechanism for the integration of geological and geophysical data to generate a three dimensional model of a reservoir that incorporates all available data.

Using the modeling process brings the disciplines together to consider a broader range of possibilities that may exist within the data sets and ways to integrate the divergent data. The traditional approach to geologic modeling was to define the reservoir through the use of horizon maps, facies distribution maps, and top and

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bottom structural maps. These were used to define reservoir thickness and geometry; then sand/shale ratios, porosity, permeability and other properties that are typically interpolated from well to well and displayed in probability distributions. This approach works reasonably well with fairly isotropic reservoir but is lacking in sufficient detail and variability for reservoirs that are more complex. Geostatistics provides a way for reservoir scientists to more closely approximate the heterogeneous nature of the earth. It will model both structural information and reservoir property data into a three-dimensional model which may be used as a basis for a reservoir simulation study.

OBSERVATIONS ABOUT RESERVOIRSThere is always a sampling bias in our subsurface data. Conventional petroleum data is extremely biased toward the current structural high points, which may have no relevance to past geologic structures. The well control is neither perfectly random nor perfectly geometrically ordered; thus having a spatial bias. Not all wells are sampled in exactly the same manner so there can be a bias in the sampling of well information. Seismic data is a well ordered dataset however it has it own set of biases. There are imaging limitations, both vertically and horizontally, that can change over the area of the survey due to changes in the acquisition parameters, changes in the processing or merging of surveys and more importantly changes in sub-surface conditions.

Geostatistical analysis is a tool to attempt to remove much of the fundamental biases as well as fill in areas of limited data with distributions of statistically valid populations of potential data. Modern workstations have many built-in algorithms that allow the creation of maps based on either limited or almost unlimited data. The algorithms used have no fundamental concepts of geologic principles so it is the responsibility of the interpreter to understand the use and limitations of each algorithm and when each can and should be applied. In the section below one of the most popular algorithms, cokriging, will be examined.

Geostatistical OverviewThere are two categories of geostatistical approaches:

► Estimation methods - best linear estimate

• Kriging, cokriging• Lacks influence of extremely high or low values

► Multiple simulation methods• Reproduces variability• Many equi-probable answers• How to rank multiple answers

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Wolf et al. (1994) describes one application of geostatistical processes:The geostatistical method is a four-step procedure that calls on several statistical tools. The first step is to quantify the spatial continuity of the well data using Variogram analysis. The second step is to find and quantify a relationship between the well and seismic data. The third step is to use what has been learned to grid the well data using the seismic as a guide via kriging with external drift. The last step is to assess the accuracy of the map just made. Traditionally, a geoscientist creates a map that is assumed correct until additional information becomes available. Only rarely is an estimate made of the map's accuracy. A geostatistician creates an expected value or average map and has a

quantitative estimate of its accuracy. Conditional simulation is a geostatistical tool that yields a quantitative measure of the error in a map.

Kriging with External Drift (KED) Cokriging is mathematically intensive and but is one of the most popular algorithms in modern workstations. Geostatisticians have also developed an external drift model (KED) to handle an ordered movement (drift) or orientation (skewness) in the data. In this approach, the guide data are directly applied in calculating the weighted averages of the grid points. Practical applications have shown little difference between cokriging and KED. This process is illustrated by Wolf et al. (Figure 2-27).

50Fig. 2-27

Fig. 2-28 Wolfe et al. (1994) demonstrates a geostatistical approach to assessment.

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Conditional Simulation Rather than developing a single "best fit" answer as in the kriging or cokriging process, conditional simulation offers a number of plausible solutions – each of which fits the conditions described; each of these equi-probable solutions is a potential answer to the conditions. Typically, a great number of solutions are derived, and statistical analyses are performed. From these analyses, the probability of any occurrence can be determined.

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Fig. 2-29 Base map with hand contoured thickness estimates.

Fig. 2-30 The same data can be computer contoured.

Fig. 2-29 Base map with hand contoured thickness estimates.

53Fig. 2-30 The same data can be computer contoured.

Fig. 2-31 The seismic horizon equivalent to the sandstone – note amplitude changes along the interval.

Fig. 2-32 Relationship between Seismic amplitude and sand thickness

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Fig. 2-32 Distribution of seismic amplitudes

Fig. 2-34 One of the realizations from the geostatistical analysis.

Fig. 2-35

55Fig. 2-34 One of the realizations from the geostatistical analysis.

Fig. 2-36 Sand Distribution

Fig 5. Projected life factor (LF = 54.3% and NOC = 1251.4) if standby time is used

Thicknesses were then arranged in ascending order and plotted on a graph, Figure 2-36. This is a compilation for sand thickness estimates at the location. In the prospect risk assessment, there were many trials run to predict the thickness of the reservoir at the prospect drill site. These predictions are shown here in a histogram. Previously it was determined that 40 feet of sandstone is required to satisfy economic minimum.

In this case, thirty-five percent of the outcomes were less than 40 feet. Risk for reservoir thickness in this prospect is therefore 0.35; which means that if you drill a prospect like this there is a 35% probability of failure based only on sand thickness. Adequacy for reservoir at this prospect location is 0.65 (1 – risk or 1.0 – 0.35). Keep in mind that when this prospect is drilled, only one thickness of sandstone will actually be found!

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Fig. 2-37

Fig. 2-38

The following map displays the data generated in the last few slides at all points on the map and computes the possibility of having less than 40 feet of sand. A preferred format would be to display the probability of having more than the economic minimum, a more positive view.

Wolfe et al. (1994) demonstrates a geostatistical approach to assessment. In their method, 200 realizations are generated for thickness of sand at a prospect location, and then ranked from low to high. Thicknesses were then arranged in ascending order and plotted on a graph (see illustration 2-38). This is an assessment curve for sand thickness at the location being considered.

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Fig. 2-39

In this example, the median sand thickness expected is 46.5 feet and there is, for example, an 80% probability of having 32 feet or more of sand at the modeled location. This type of analysis can be conducted for any location on the map or for any number of parameters. Another possibility with the data set is to plot the economic threshold for a specific location and then directly read the probability of exceeding that value. Figure 2-39 demonstrates that approach.

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Fig. 2-41 Risk assessment curve.

Risk Assessment CurveThe final step in this evaluation process would be to combine the chance of adequacy predictions with the unrisk assessment curve (Figure 2-41). The combination results in a second curve, the risk assessment curve. This display will represent our full assessment of the potential sizes of the successful evaluated accumulation and its chance of adequacy. The risk assessment curve demonstrates the probability of finding each reserve amount. The difference with the unrisk curve is that the risk curve considers those cases that are dry holes or less than economic minimum. In this example, the average result of all cases, successes, and failures, has a risk mean reserves of

35 million barrels. This value is derived by multiplying the unrisk mean reserve (140 million barrels) by the prospect adequacy (0.25).Risk reserve calculations can be very misleading. The curve does not represent reality; it represents the statistically adjusted results if a significant number of tests just like this one were drilled. It combines the volumes for successes and failures, artificially reducing the mean size of successful prospects. To use this curve for decision-making for a single test gives simulated results that do not reflect realism.A question then follows; if a risk-adjusted assessment does not represent reality, why make the calculation? The easy answer is that

when a drilling program is considered, the sum of the risk means should equal the total reserves found in a successful program. It does not identify which prospects will contribute reserves and which will be failures. Used carefully, the risk mean may be employed as a tool to compare prospects or plays. In summary, risk mean reserves are important estimations if a population is considered, but dangerous when applied to a single prospect.It is extremely important to establish a standard throughout the organization so that there is a consistent assessment by which to compare business options. This allows for a common platform for consideration of prospects generated worldwide to be compared on a fairly even basis.An important aspect of risk assessment is to convert the assessment that is most often expressed in qualitative terms into a quantitative measure. It is recommended that measures as shown above be applied across the organization to normalize these judgments.

Some practical steps your company can take:

► Establish a single standard throughout the organization in order that

• Assessments can be compared on the same basis• Assessments are consistent through time

► Make sure that the assessments are compatible with the corporate:

• Business processes• Language• Comfort for risk• Culture

► Implement training that includes practice in making consistent assessments

► Conduct Prospect after drill reviews to define risking success

Risk assessment is an important tool in aligning the work and activities of explorationists with the business of the organization. To learn more about risk assessment in prospects or plays, we recommend enrolling in the upcoming session of Prospect and Play Assessment (PPA).

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GET THE MOST OUT OF A PETROSKILLS COURSE

Published April 2019Written by: Ken Lunsford

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Have you ever wondered how to get the most out of a training course? Every year, we have thousands of participants who go through the process of selecting, attending and applying PetroSkills training. This tip of the month provides a guide to help you have the most impactful training experience and apply your newly learned knowledge to your career.

In this article, we will discuss how to:

1. SELECT THE RIGHT COURSE “I had a ship’s captain and a land surveyor show up for an advanced

project management course. During a different session I had four business,

accounting and contract administrators attend one of my intermediate pump and compressor selection courses.

I did my best to give them value for their time. Careful selection of

courses will pay significant dividends and reduce situations like these.”

- PetroSkills Instructor

Start with selecting the discipline of the field you work in, and then determine your level of competency.

Address the following questions:Has your competency been objectively assessed?• Self-Assessment• Supervisor or subject matter expert assessment

How does your competency need to be increased?• Raise competency in skills areas where it is below the target level• Increase competency in strong skill areas by challenging yourself with advanced courses

Using the information identified by your competency assessment it is time to start selecting the appropriate course. Visit the potential course pages to read the course descriptions and learning objectives to determine if the course addresses your needs.

How to Use a Course ProgressionAs an example, the PetroSkills project management course progression, shown below, depicts the 2019 coverage of our courses. Early career project managers often benefit from Foundation level courses, and mid-career project managers can choose

from a broad selection of general, focused and related intermediate courses. Advanced courses deal with specialized topics found in international petroleum mega projects and programs.Each of the disciplines in PetroSkills has a course progression chart that can be used to begin the search for the right course.

64Fig. A Course progression

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2. ACTIVELY LISTENActive listening is crucial to absorbing the information taught in a course. In fact, according to Harvard Business Review, two months after listening to a talk, the average listener only remembers about 25% of what was taught.1 Their point being, if you barely learn something you are not going to retain the information after time passes.

Tips:• Be purposeful — Arrive with a learning goal based on your competency needs and the issues/ challenges you are facing on your job.

• Engage — Participate in discussions and contribute to the group’s learning

• Avoid distractions — Put your cell phone away! Calls and texts can be returned during breaks.

• Take good notes — This will help you stay focused and make connections between topics.

• Reflect –- The greatest learning occurs when participants reflect on an issue and build upon prior knowledge

Active listeners ask four questions while they listen to each topic.1. What problem will this content help solve?

2. What is being said in detail, and how is it being said?• For project management and business professional courses, this question is about discovering the key points, assertions and arguments that constitute the instructor’s recommended practice.• For technical courses, this question is typically about applying scientific principles, techniques, and equations to produce models and design concepts for petroleum subsurface, drilling and surface facilities.

3. Is the information valid? - Active listeners will pay attention to evidence that supports the main ideas and the detail that supports the development of calculations and technical designs.

4. Why does this matter? - The best listeners will walk away from a course knowing why the information is relevant in today’s industry and be able to apply the concepts to their work.

Taking NotesNote taking is a critical part of learning while attending a training course. I recommend marking up the provided copy of the slides as you go along. The following are some examples of keywords, phrases and major points that should be underlined or highlighted. Jotting a note in the margin about a key point or section not fully understood will help you recall it later.

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Note Strategy: For your first set of notes taken during the course.Your note strategy should vary depending on if the course is technical or non-technical. Read through the recommendations below:

It is highly recommended that you do a second set of notes during the evening:

► Clean up and organize your first set of notes

► React to what you have heardIf you do not understand a section from the previous day you should always feel free to discuss it with the instructor for clarification.

3. QUESTIONSome disciplines, such as project management, are not a pure science and the instructor will often be making recommendations regarding the “best way” to manage a project. It is your responsibility as the learner to decide if it is sound. Think of the recommendation in terms of a house - the roof is the proposed method and the walls are the supporting rationale. You need explanations and evidence to support the proposal because without them the roof will fall.

What types of evidence should you be looking to support the argument?

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When an explanation is offered, ask yourself:

Is it possible?

► Is the explanation still workable on closer examination?

Is it plausible?

► Is it reasonable to think that something like this might have taken place, given the evidence?

Is it probable?

► Is it the best explanation, considering the competing options?

► Believability always sides with the most likely choice.

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4. DEBRIEFMany instructors will go through a debriefing exercise at the end of each section.

Three questions are often asked:

Contribute by looking back at your notes, reflecting on your key points and joining the discussion.

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Getting the most out of a PetroSkills course requires:

► Selecting the right course using competency gap analysis

► Scrutinizing course descriptions to ensure a needs match

► Actively listening and contributing to discussions

► Taking notes and reflecting on each day’s content

► Developing and asking questions that deepen understanding

► Participating in section debriefs to explore the significance of the learning

► Developing a plan to put what you have learned to work

Use this structured approach to select the right course, maximize your learning and improve your company. Becoming a “student of the game” is the first step on the journey to greater knowledge and skill.

5. PLAN FOR ACTION BACK AT WORK

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Ken Lunsford is the project management discipline manager at PetroSkills and teaches the following courses:

Project Management for Engineering and Construction - FPM22

Advanced Project Management - FPM62

Project Management in Upstream Field Development - FPM2

Turnaround, Shutdown and Outage Management - TSOM