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Elsevier Science
Reservoir Exploration and Appraisal

Reservoir Exploration and Appraisal

by Luiz AmadoLuiz Amado
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Finding a new oil and gas discovery and evaluating its volume is a difficult and challenging task, and yet there is very little published on the topic. Luiz Amado delivers a one-of-a-kind introductory guide titled Reservoir Exploration and Appraisal. Providing logistical instruction and processes for the entire exploration and appraisal process, Amado furnishes the guidance, workflow, and practical recommendations needed based on real-world scenarios. Written by an engineer with over 15 years of experience in the North Sea, Gulf of Mexico, South America and West Africa, Reservoir Exploration and Appraisal equips engineers and economists with expert advice on critical subjects such as detailed methods of estimating recovery factors, creating production curves using either simple or complex approaches, understanding main fluid and rock properties that govern volume and productivity, and communicating examples of field case evaluations, including deepwater projects.

  • Details methods of estimating recovery factors and rules of thumb that can be used if there is an absence of data
  • How to create production curves using either simple or complex approaches
  • Understanding main fluid and rock properties that govern volume and productivity, saving time from analyzing countless fluid samples or rock data from cores
  • Describes the process of lease sales, bid rounds and farm-in opportunities
  • Communicates examples of field case evaluations, including deepwater projects, to illustrate the steps covered in the book, showing the reader the full project cycle

Product Details

ISBN-13: 9781856178532
Publisher: Elsevier Science
Publication date: 05/10/2013
Pages: 152
Product dimensions: 6.00(w) x 8.90(h) x 0.50(d)

Read an Excerpt

Reservoir Exploration and Appraisal

By Luiz Amado


Copyright © 2013 Elsevier Inc.
All rights reserved.
ISBN: 978-1-85617-854-9

<h2>CHAPTER 1</h2>

<b>Project Framing and the Volume to Value Evaluation Analysis</b></p>

Volume to value (VV) is the methodology used by the petroleum companies for the economical evaluation and selection of exploratory opportunities. An exploratory opportunity is the anticipation of a given accumulation of oil or gas based on seismic sections and well data. Using these inputs and a certain degree of knowledge, interpretation, and imagination, it is possible to construct a geological model (a volume defined by several areas, contours, and variable thickness) that will represent the structure of the prospect.</p>

Thus, the search for exploratory opportunities will contain a high degree of uncertainty and risk. The models, based on seismic section and nearby well data, will provide a conceptual design but until one exploratory well is drilled no presence of hydrocarbons can be assumed.</p>

In order to acquire prospects, oil and gas companies usually have to take part in a bid round or lease sale when blocks or cells will be offered for a given period of time after paying a signature bonus to acquire them.</p>

These blocks vary by size depending on where in the world they are located. In the Gulf of Mexico (GOM), they will be a square with sides of 3 miles by 3 miles. In other parts of the world, the sides of the blocks can be 10 times bigger, as for example, offshore Brazil. <b>Figure 1.1</b> provides an overview of lease blocks in Campos Basin (offshore Brazil).</p>

Companies will search for blocks where it is believed that several geological factors have combined together to produce oil or gas accumulation. These factors are presented in <b>Table 1.1</b>.</p>

Volume to value (VV) is therefore a process of identifying a prospect, calculating its volume, and converting it to a monetary value. <b>Figure 1.2</b> shows the VV workflow.</p>

Colors are used for simplification purposes only and have no intrinsic meaning. In simple terms the overall procedure involves the identification of a prospect, followed by estimating its volume, and building a developing plan to recover this volume using wells and facilities, which will demand capital and operational expenditure in order to drill, construct, and place at the field to enable extraction of the resources (volume) over the course of time.</p>

The volume, once at the surface, will be sold to recover the costs.</p>

The flowchart depicted in Figure 1.2 is self-explanatory. However, let us describe the activities shown there.</p>

1. Geophysics and geology (G&G) modeling—The entire process starts here, with the delineation of the leads and prospects and an estimation of the volumes in place. The volumes will also define the number of exploratory wells needed to be drilled to prove and discover them.</p>

2. Reservoir engineers will then estimate recovery factors (RFs) (according to the rock and fluid properties associated with the accumulation) to apply to those volumes, thereby converting them to recoverable volumes.</p>

3. At the same time they will define the number of development wells (and appraisal wells) and create production profiles that will produce the recoverable volumes with time.</p>

4. Possible development scenarios will be created, each one with their own production and cost profiles. Exploration and appraisal well costs, development well costs, facilities and subsea costs, and operational costs will be estimated and updates on market factors as well as contingency will be added.</p>

5. This initial development scenario, will then be passed to the local company that will operate the field and their assumptions will be incorporated, such as fiscal regimes, oil and gas prices, and contracts in place as well the tax and royalties due in that particular country.</p>

6. Economics analysis will be assessed and net present value (NPV) and expected monetary value (EMV) figures will be created for all scenarios.</p>

7. A curve, known as a nomogram (NPV plotted against recoverable volumes) will serve as a guide to determine what scenarios are NPV > 0 and those that are NPV < 0 (<b>Figure 1.3</b>).</p>

8. Cutoff volume will then be defined as the intersection on the <i>x</i>-axis that corresponds to NPV = 0.</p>

9. This cutoff will then indicate to the subsurface team the minimal volumes that should be discarded.</p>

10. New mean success volumes (MSV) will be estimated, as we know that we should not use the whole distribution curve of volumes but only that part which produces NPV > 0 projects.</p>

11. The whole cycle is then repeated,, the final economics guiding the decision makers in ascertaining what the best approach for the project.</p>

In the next chapter, we will start with the identiffication and definition of the plays, leads, and prospect.</p> <h2>CHAPTER 2</h2>

<b>Setting the Scene: Plays, Leads, and Prospects</b></p>

In order to understand some of thhhhe concepts in this book, we need to define play, lead, and prospect. The definitions given in this chapter are taken from the Internet.</p>

<b>2.1 DEFINITION OF PLAY</b></p>

In geology, a petroleum play, or simply a play, is a group of <b><i>oil or gas fields</i></b> or prospects (definition of prospect will follow) in the same region that are controlled by the same set of geological circumstances.</p>

A particular <b><i>stratigraphic</i></b> or <b><i>structural</i></b> geologic setting is also often known as a play. For example, in a relatively unexplored area such as the <b><i>Falkland Islands</i></b>, one might speak of the "Paleozoic play" to refer to the potential oil reserves that might be found within the <b><i>Paleozoic</i></b> strata.</p>

Another example would be the recent presalt play in Brazil that refers to the strata below the salt layer that was formed before the salt precipitated. In a well-explored basin, such as the <b><i>Gulf of Mexico</i> (GOM)</b>, explorationists refer to the "Wilcox play" or the "Norphlet play" to collectively designate the production and possible production from those particular geological formations of <b><i>Paleocene</i></b> and <b><i>Jurassic</i></b> age, respectively.</p>

A play may also be a broad category of possible reservoirs or rock types, as in the turbidite play of offshore <b><i>Angola</i></b> or the carbonate play in the East Java Sea, or refer to the structural geology of the setting, as in the subupthrust play of <b><i>Wyoming</i></b>.</p>

Sometimes the word play is applied to a geographic area with hydrocarbon potential, for example the South Texas play or the Niger Delta play, but usually "play" is used with the sense of restricting discussion to exploring a particular geological setting.</p>

Thus, one might have both the Wilcox play and the Norphlet play (among others) in partially overlapping areas of the coast of the Gulf of Mexico (GOM); the GOM deepwater play might or might not include elements or particular locations appropriate to either the Wilcox play or the Norphlet play, or to both. The term play may refer to geologic time intervals, rock types, structures, or some combination of them.</p>

<b>2.2 DEFINITION OF LEAD</b></p>

A lead in <b><i>hydrocarbon exploration</i></b> is a subsurface <b><i>structural</i></b> or <b><i>stratigraphic</i></b> feature with the potential to include entrapped <b><i>oil</i></b> or <b><i>natural gas</i></b>. When exploring a new area, or when new data become available in existing acreage, an explorer will carry out an initial screening to identify the possible leads.</p>

Further work is then concentrated on the leads with the intention to mature at least some of them into drillable <b><i>prospects</i></b> (<b>Figure 2.1</b>).</p>


A prospect would be an identified volume or accumulation as a result of further work done on a lead in a given play. It is a well-defined structure with a known volume and offering a real possibility for drilling an exploratory well to prove (a) it is there and (b) contains hydrocarbons (<b>Figure 2.2</b>).</p> <h2>CHAPTER 3</h2>

<b>Exploration and Appraisal Phases</b></p>

Once the prospect has been identified and is ready to be drilled, an initial exploratory well is created. This well will discover the accumulation and prove the assumptions made.</p>

The exploration phase comprises the work done by geoscientists to interpret seismic sections, build top and base structure maps, and define the location for an exploratory well and subsequent appraisal wells. Some prospects, owing to their size, may not always require an appraisal well.</p>

<b>3.1 EXPLORATORY WELLS</b></p>

Usually, a prospect will have one or two exploratory wells, depending on its size and degree of reservoir compartmentalization. Exploratory wells will be planned to test a given volume or area and not the whole prospect. Once the well is a discovery, other wells called appraisal wells will be necessary to delineate the extension of the reservoir and the fluid contacts (not always found in an exploratory well).</p>

On the other hand, in a case where the exploratory well finds no hydrocarbons or misses the reservoir, the prospect will be abandoned. In the past 4–5 years, approximately 40 exploratory wells have been drilled in the deepwater Gulf of Mexico (GOM), with a success rate inferior to 50%, meaning that about half of the wells did not find any commercial volumes of oil or gas (<b>Figures 3.1–3.3</b>).</p>

<b>3.2 APPRAISAL WELLS</b></p>

To define the number of appraisal wells is a bit more complex. In this case, as the objective is to delineate the reservoir and test other features it becomes not only a function of volume but also structurally complex.</p>

<b>Figure 3.4</b> provides a quick method of estimating the number of appraisal wells as a function of reservoir recoverable volume (in millions of barrels of oil equivalent). It is supported by field analogs as found in the literature (shown in the figure as blue triangles).</p>

To use the chart, enter the recoverable volume of your prospect and find where it intersects the "staircase" line. The number of wells will be read out on the <i>Y</i>-axis. If a fractional number is found, it should be rounded up or down. Remember that the number of appraisal wells will not only be dictated by the volume but also by the complexity of its reservoir structure.</p>

As can be seen, there are a number of prospects for which, for a range of volumes, the number of appraisals is the same. This is due to the fact that a small volume may be too complex or a large volume may have continuity and both will need the same number of appraisals regardless of the size or volume. Note that a maximum number of five is the upper limit as seen in the chart.</p>

As an example, a recoverable volume of 300 MMboe (barrels of oil equivalent) will at first sight require two to three appraisal wells. A gas reservoir of 480 bcf (billions of cubic feet), approximately 80 MMboe, will require one or maybe two appraisal wells depending on its structure.</p>


The exploration and appraisal phases of a particular project will vary of course depending on the volume, number of wells, and drilling time required to drill all the wells. On an average, we can assume that a company will drill an exploratory well and the subsequent appraisal wells over a period of a maximum of 3–4 years, usually drilling one or a maximum of two wells per year. This is valid for deepwater offshore wells, with depth ranging from 15,000 to 30,000 ft below the seafloor. The deeper the well, the more expensive it will be and the more time will be required to finalize it.</p>


Seismic and subsurface studies costs should be considered in the volume to value (VV) workflow as an exploration and appraisal associated cost. Offshore seismic costs can vary from 3 to 10 MM$.

Excerpted from Reservoir Exploration and Appraisal by Luiz Amado. Copyright © 2013 Elsevier Inc.. Excerpted by permission of Elsevier.
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Table of Contents

Preface Introduction Chapter 1: Project Framing and the V2V (Volume to Value) Evaluation Analysis Chapter 2: Setting the Scene: Plays, Leads and Prospects Chapter 3: Exploration and Appraisal Stages Chapter 4: Rock and Fluid Estimates Chapter 5: The Search and Use of Analogues Chapter 6: Volumes and Recovery Efficiencies Chapter 7: Wells and Production Functions Chapter 8: Facilities and Subsea Engineering Chapter 9: Capex and Opex Expenditures Chapter 10: Lease Sales, Bids and Farm-in Chapter 11: The Value and Gains of Technology Chapter 12: Examples and Field Cases Evaluations Index

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