2. Development Geology• Hybrid discipline: geology on the field and reservoir scale.• Requires good knowledge of many disciplines. – Structural Geology. – Stratigraphy and sedimentology. – Reservoir engineering. – Drilling methods and engineering. – Petrophysics. – Seismology. – Petroleum Economics and land management. – Organic geochemistry……..
3. Why have a development geologist• Not all companies do! …this is becoming less common.• Engineers, Geologists and Geophysicists don’t just specialize in different fields, they think in different ways.• There is a communication problem: the development geologist must be able to bridge the gap.
4. The Energy Crisis• Size of discoveries decreasing.• Reserves declining.• New opportunities must be derived from old plays and systems.• Existing reserves must be economically extracted.• Modelling and understanding petroleum systems as a whole is an essential skill.
5. • Importance of the Development Geologist will progressively increase:• Additional reserves required from known occurrences• Older discounted reserves need to be reassessed• Remember, about 60% reserves are left in the ground.
6. Principal responsibilities of the Development Geologist• Estimation of Volumetric Reserves• Justifying drilling options• Providing a framework for maximum financial return for his company
7. • Exploration Group discovers a field• Responsibility for the field passed to the DG.• DG must develop the field as economically and efficiently as possible.• Input needed from geologists, engineers, drillers, financial whizzkids….need to be able to talk to all these experts.• 4 broad areas of responsibility lie within the title DG:
8. 1. Predevelopment Evaluation• After discovery of field.• Exploratory wells & delineation wells are drilled – Evaluate field for reserves and design criteria.• Very important stage in offshore areas – Large capital investment: got to get the design right – Essential that this phase is done correctly
9. 2. Development Drilling• DG is responsible for: – Initiating development well recommendations – Monitoring these wells during drilling – Adjusting development plans as wells are drilled
10. Well Surveillance• Generally handled by the reservoir engineer – However, when performance is not as expected or when remedial work is required (workover) the DG inputs geological constraint.• RE & DG work together to evaluate unusual reservoir performance• RE & DG then make remedial recommendations
11. Field Studies• One of the most important roles of the DG.• Re-evaluation of old fields and recognition of new opportunities in these fields. – This role will become increasingly important in the future as reserves decrease. – The days of wild-catting are long gone.
12. Development Geology in a major Oil Company• 5 general subdivisions within a large oil company (NOC, IOC..). Do not confuse these with the oil process previously described in this course. – Exploration – Production • E&P generally combined – Refining – Transportation – Marketing
13. Common employment positions in E&P and the disciplines hired to fillthem in a large oil company
14. Development Geologist in small or independent oil companies• These companies don’t have the resources to hire specialists in all the areas.• E&P: generally a geologist/ geophysicist combination.• Production: a petroleum engineer• Otherwise, a single geologist fills E&P and consultants are used for everything else.
15. The Independent Petroleum Geologist• A real fun occupation: exciting career for a petroleum geologist• Must develop and produce an attractive prospect alone and get wells drilled• Must understand the methods by which a prospect gets financed: the “third for a quarter” deal
16. Important definitions• Overriding Royalty Interest – An ORI owner gets a percentage off the top (before operating expenses. – An ORI owner has no financial obligation – Can be obtained by writing a book, mineral leases or generating prospects in the oil business: lucrative.• Working Interest – Receives income but has financial obligations – All costs incurred are the working interest owners responsibility• Operator – Individual or company responsible for getting the well drilled, usually the principal working interest owner in the field
17. The Petroleum “Deal”. How a petroleum geologist gets a overriding royalty interest in a well and his/her company gets a working interest in a well AS you can see, with no investment on his part, the prospect generator gets an Royalty Interest: must, by law, for paid overriding royalty interest just be defining and justifying where to drill. Overriding Royalty Interest: commonly1/4 2-10% availablethe maths: Do for the people who make ORI =deal the 3% 500 barrels a day production Investment companies thirdtop a You get 3% of the oil off the for3/4 quarter interest Oil sells at $40 a barrel You make $600 per day or $18,000 per month from ONE well
18. In conclusion• Development geology is not only a rewarding, but a lucrative field for the small and independent operator.• In the future, this field (which requires skills in many fields) will become more important as reserves decline.• The bottom line in all petroleum exploration is financial, and economic evaluations require input from many disciplines: the DG must have these skills.• The most important ability is RESERVE ESTIMATION
19. Reserves EstimationProcesses, terminology and prediction curves
20. • A well will not be drilled just because the geology is good.• Wells get drilled because the geology is good and there is potential for economic gain.• The most important role os a DG is to: – estimate the oil and gas reserves that may be discovered in a particular venture. – keep track of the reserves in all past ventures.
21. The 4 Basic Reserves Estimation Methods1. Educated Guess2. Comparison with nearby production.3. Reservoir Simulation – material balance calculations4. Volumetric Calculations
22. 1. The Educated Guess• Historically wells were drilled by wildcat techniques: some of the largest US discioveries were made in this way.• Even today some wells are drilled without an economic analysis, largely due to contract obligations.• Very unlikely these days that you will get to drill a well because you have a gut feeling about a particular area.
23. 2. Comparison of nearby production• Consider a region where production is from a highly fractured tight formation or where poroperm heterogeneity is unpredictable.• Volumetric calculations are largely meaningless.• A way to estimate potential production from a well is to consider those nearby.• Generally, such a wildcat well will not perform better than the nearest wells: best to estimate cautiously
24. 3. Reservoir Simulation• Reservoir Modelling: primarily the reservoir engineer’s job.• Commonest simulation model – finite difference model• Reservoir is modelled in terms of shape and: – Porosity – Permeability – Fluid saturations – Pressure – Barriers and baffles….• Internal reservoir conditions are then modelled: problem- the best models are built after drilling development wells.
25. 3. Reservoir Simulation: Decline Curves• After wells have been producing for a while:• Decline rate of production is graphed• Generally 6 months-1year after start of production• Good reserves estimates can be derived.• Often compared with volumetric technique results.• We will look at decline curves in detail later in the course.
26. 4. Volumetrics• Most accurate and widely used methods of reserves estimation.• Carried out by geologists as they are based on geological structure and isopach maps.• Rock volumes are established that are assumed to contain hydrocarbons (e.g. seismic bright spot).• Can be a simple volume calculation or a complex net gas or net oil isopach approach, determined by structure contours modified by fluid contacts and net reservoir thickness isopachs.
27. • Most rock volumes established through use of net gas and net oil isopachs.• Constructed from structure contour maps with well defined OWC and/or GOC.
28. Once rock volume is estimated, the in place oil and/or gas is calculated by:1. Determination of pore volume – = rock volume x average porosity – Average porosity generally from well logs or engineers2. By subtraction of water saturation, connate or free water in the reservoir rocks. – Water saturation numbers generally calculated by petrophysicists or engineers3. Correcting to sales line temperature and pressure by using Formation Volume Factors – FVF generally determined by reservoir engineers
29. Points of note• Not the difference: – In place volume = total oil/ gas – Recoverable volume= that percentage that can actually be produced as estimated by a recovery efficiency (average 35%)• All reserves are expressed in surface or pipeline units – Gas at reservoir conditions occupies less volume than at surface. – All are converted to a common sale pressure base. – Conversely, oil shrinks on its way to the surface
30. Formulae for Volumetric Reserve Calculations
31. Quantifying uncertainty in reserves estimates• ALWAYS uncertainty in estimates, hence we always construct minimum, most likely and best-case estimates – If you were putting your money into a venture, which would you base your financial analyses on?• In addition, we must always speak the same language: terminology is essential in understanding what reserves have been offered to you for investment – Reserves are anything that can be recovered economically under current economic and technological conditions. – Reserves are classified as Proved or Unproved – what do we mean by this? – NB. A Reserve is not a Resource: A resource is anything that could become economic given certain developments in the future. Do not confuse the two (as many do)
32. Reserves: Proved• Estimated to reasonable certainty• Often based on well logs but normally requires actual production or formation tests.• Can be: – Proved developed reserves • Reserves that are expected to be recovered from existing wells – Proved undeveloped reserves • To be recovered by new drilling, deepening wells to a new reservoir or where additional finance is required to produce
33. Reserves: Unproved• Based on similar data but contractual, technical or financial constraints prevent them from being classified as proved.• Can be: – Probable Reserves • Less certain than proved but can be assessed to some degree of certainty • May include logging estimates, improved recovery technique estimates – Possible Reserves • Not as certain as probable reserves and can only be estimated to a low degree of confidence.
34. Decision Making: protocol• Despite these defined terms, there is still some latitude in their application. In general, we use this:• Proved Reserves – = minimum case economics. Financial investment is based on proved reserves.• Proved + Probable Reserves – = most likely case economics. Internal company decisions usually based on this.• Proved +Probable + Possible Reserves – = maximum case economics. This is the best that could reasonably happe for a venture. Companies try to sell ventures based on this.
35. Decision Making: projected income analysis• Standard diagram for major oil companies to base their decisions on drilling and development is a Reserves/ Potential Income Diagram.• Best shown with an example:• Consider a company deciding whether to spend $50m on the development of a field by building an offshore platform….
36. Economists then provide estimates of likely oil price on production at: Max: $40 per barrel Most Likely: $25 per barrel Min: $15 per barrel This allows us to project best and worst case scenarios for the well development. 200 Projected Income (MM$) Maximum 160 Profit 120 80 Expected Capital 40 At Expenditure Costs Risk 0 1 2 3 4 5 6 MINIMUM MOST LIKELY MAXIMUM Reserves (Million bbls) If minimum is true: company will lose $10 – 25 million.From other wells, geologists estimate recoverable reserves at: Max: 5,000,000 barrels (provedprofit will be made. If most likely is true: + probable + possible) Most Likely: 3,000,000 barrels (proved + probable) Min: 1,000,000 barrels (proved)
37. • As you can see, accurate estimation of reserves is essential.• Moreover, a knowledge of the financial implications of terminology and your assessments is critical.• This is a fun and challenging aspect of the business IF YOU ARE GOOD AT IT.
38. Reserves Estimation IISubsurface Maps and Volume Estimation
39. Isopach Maps• Graphical representation of the vertical thickness of a particular unit or feature. – Vertical thickness of reservoir – Vertical thickness saturated with oil – Vertical thickness saturated with gas…• Not to be confused with Isolith Maps – True stratigraphic thickness of a lithological horizon.• In reserves estimation, the Isopach maps are projected onto the flat map surface. Isolith maps must be rotated to account for dip.
40. • Overlying a structure contour map with an isopach map allows determination of the true vertical thickness of a unit of interest within a particular structure (e.g. trap)• Designing an isopach map: – Lot of data and reservoir irregular: make contour intervals small. – Little data and/or reservoir regular: larger contour intervals (shortcut)• Different types of isopach map – Gross sand thickness isopachs – Net pay thickness isopachs – Variable reservoir thickness isopachs
41. Gross Sand Thickness Isopachs• GST = total thickness of rock saturated with oil or gas irrespective of• Tight zones• Low porosity areas• Low permeability areas etc..• Easy to make, especially for gas• Zero contour = downdip limits of gas (GOC or GWC)• Gross isopachs should increase updip correspondingly with the structure contour elevations
42. • E.g. if GWC is at -7,000’ subsea, then the following isopach lines should overlay the structure contour lines as shown:Structure Contour Line Gross Isopach Line-7000 0-6980 20-6960 40• Until sand becomes full or top of structure is reached.• For oil, the OWC will plot similarly, although the presence of gas on top will cause updip wedging (decreasing thickness) of the gross oil isopach
43. Net Pay thickness isopachs• Refers to the gross reservoir thickness with tight zones thrown out.• If the reservoir is homogeneous we can simply take the net to gross of the reservoir and multiply the thickness of the unit by this reduction.• Otherwise, heterogeneity can considerably complicate matters.
44. Variable reservoir thickness isopachs• Reservoir thickness changes rapidly – e.g. edge of reef, channel – Requires a net reservoir thickness isopach map• GWC or GOC = structure contour (zero gas line) but this will veer away from the structure contour where the sand thickness disappears (can’t have gas where there is no reservoir)• Basically, the thicknesses are modified so that the net gas or net oil thickness isopachs do not exceed the thickness of the reservoir.
45. Calculations from isopachs• Trapezoidal Rule – Used to calculate rock volume from an isopach: BV = (h/2) [A0 + 2A1 + 2A2 + …+ 2An-1 + An] +hnAn/2Where BV = bulk volume (acre feet) h = contour interval A0 = area enclosed by zero contour line A1 = area enclosed by first contour line An-1 = area enclosed by first contour line above top contour An = top contour line hn = vertical distance from top contour to top of reservoir i.e. take the average area between two intervals and multiply that area by contour interval thickness to get the volume it encloses.
46. GOC or GWC 0’ 20’ h = contour interval = 20’ 40’ A 54’ B Illustration of the Trapezoidal Rule: Net gas isopach over the top of a max h = 54’ dome.hn = 60 – 54 60’ = 14’ An 40’ A1 20’ A h = 20’ B A0 0’ GOC or GWC BV = (h/2) [A0 + 2A1 + 2A2 + …+ 2An-1 + An] +hnAn/2
47. GOC or GWC 0’ 20’ 40’A B 54’ Useful Shortcut Area of the top of a sphere is remarkably close to the result of max h = 54’ multiplying the base area A0 by ½ the maximum thickness 60’ i.e. 0.5 x 54 = 27 ft An 40’ A1 20’A B A0 0’
48. Wedge of gas filled sand here 0’ Reservoir is full of gas to the base of the sandstone in this area Fa ’ ult 20 A ’ ’ 54 40 = h ax m C D SAND FULL LINE lt B Fau Fault A 60’ Max h = 54’ 40’ C 20’ D 0’ Fluid Contact Sand Full above this pointWell drilled here will find gas and oil or water Well drilled here will find only gas
49. Knowing the volume is only part of the story….the well must be economic