Petroleum geology and of reservoir GEO 521.pptx

For students studying geology

1. GEO 521: PETROLEUM GEOLOGY

2. INTRODUCTION Petroleum geology is general geology with a specific aim , of finding oil an gas. The geology of petroleum is largely the geology of sedimentary basins because it is in sedimentary basins that the commercial accumulations of petroleum occur. It is therefore essential to have a clear understanding of sedimentary basins in general. The petroleum geologist’s work also has its descriptive and interpretive aspects, but the emphasis tends to linger on the descriptive because the goal of petroleum geology is a deterministic model of the area under study - ultimately, the oil or gas field. To achieve this goal, the specialists of petroleum geology tend to work in teams (which also broadens their minds). Petroleum geologists , whatever their speciality , tend to become either exploration geologists or development geologists . The difference is not only a matter of scale, but also of outlook that can be so different that there is danger of the one not understanding the other properly. Petroleum exploration , in its simplest terms, consists of studying large regions that do or could contain petroleum, identifying progressively smaller areas of progressively greater interest in these until a prospect worth drilling has been identified, and discovering oil or gas in one or more of these. The development geologist starts with the discovery well and a detailed seismic survey , and locates appraisal wells to assess the size and nature of the accumulation or accumulations. If petroleum is found to be in commercially viable quantities , the development geologist seeks to obtain an accurate model of the accumulation on maps and cross-sections that can be used for estimating the recoverable reserves and the siting of development wells that will produce these reserves as efficiently as possible. 2

3. ORIGIN OF PETROLEUM Petroleum is found in unmetamorphosed   marine (shallow, deep water) and continental sediments , and occur in porous material totally encapsulated from other porous material. Traces of indigenous hydrocarbons are also found in igneous and metamorphic rocks and in Chondritic meteorites. Chemical observations are: crude oil ( even numbered carbon chains ) differs from recent hydrocarbons ( odd numbered carbon chains ) formed in shallow environments  crude oil has over 50% light hydrocarbons while light hydrocarbons are rare or absent in the recent variety. 3

4. Inorganic Origin There are two theories of origin: Organic (bionic) and Inorganic ( abionic ). Early theories postulated an inorganic origin when it became apparent that there were widespread deposits of petroleum throughout the world. Deep-seated terrestrial hypotheses: Two theories are: Acetylene theory: Dmitri Mendele'ev (1877), a Russian and the father of the periodic table of elements, reasoned that metallic carbides deep within Earth reacted with water at high temperatures to form acetylene (C 2 H 2 ) which subsequently condensed to form heavier hydrocarbons. This reaction is readily reproduced in the laboratory. Modified acetylene theory: Berthelot (1860) and Mendele’ev (1902) theorized that the mantle contained iron carbide which would react with percolating water to form methane: FeC 2  + 2H 2 O = CH 4  + FeO 2   The problem was and still is the lack of evidence for the existence of iron carbide in the mantle. Extraterrestrial hypothesis: Sokoloff (1890) proposed a cosmic origin. His theory explained that hydrocarbons precipitated as rain from original nebular matter from which the solar system was formed and then ejected from earth's interior onto surface rocks. 4

5. 20 th Century variants and a renewed interest to the inorganic mode of origin by others was caused by two discoveries: Existence of carbonaceous chondrites (meteorites) and the discovery that atmospheres containing methane exists for some celestial bodies such as Saturn, Titan, Jupiter . The only known source for the methane is through inorganic reactions. The discovery by Mueller (1963) of a type of meteorite called carbonaceous chondrites, led to a renewed interest in an inorganic mechanism for creating organic compounds. Chondritic meteorites contain greater than 6% organic matter (not graphite) and traces of various hydrocarbons including amino acids. It has been postulated that the original atmosphere of the earth contained methane, ammonia, hydrogen, water vapor ; add to this photochemical reactions (due to UV radiation) and the result is the creation of an oily, waxy surface layer that may have been host to a variety of developing prebiotic compounds including the precursors of life . The chief support of an inorganic origin is that the hydrocarbons: methane, ethane, acetylene, and benzene have repeatedly been made from inorganic sources. For example, congealed magma has been found on the Kola Peninsula in Russia containing gaseous and liquid hydrocarbons (90% methane, traces of ethane, propane, isobutane). Paraffinic hydrocarbons have also been found in other igneous rocks. 5

6. Problems With Inorganic Theories There is no direct evidence that will show whether the source of the organic material in the chondritic meteorites is the result of a truly inorganic origin or was in an original parent material which was organically created . Similar reasoning applies to other celestial bodies. There is no field evidence to show that inorganic processes have occurred in nature, yet there is mounting evidence for an organic origin . There should be large amounts of hydrocarbons emitted from volcanoes, congealed magma, and other igneous rocks if an inorganic origin is the primary methodology for the creation of hydrocarbons. Gaseous hydrocarbons have been recorded emanating from volcanoes, with methane (CH 4 ) being the most common. Volumes are generally less than 1%, but as high as 15% have been recorded . But large pools are absent from igneous rocks. Where commercial accumulations do occur, they are in igneous rocks that have intruded into or are overlain by sedimentary materials ; in other words, the hydrocarbons probably formed in the sedimentary sequence and migrated into the igneous material. 6

7. Organic Origin There are a number of compelling reasons that support an organic origin hypothesis. Carbon and Hydrogen are the primary constituents of organic material, both plant and animal. Moreover, carbon, hydrogen, and hydrocarbons are continually being produced by the life processes of plants and animals . A major breakthrough occurred when it was discovered that hydrocarbons and related compounds occur in many living organisms and are deposited in the sediments with little or no change . Nitrogen and porphyrins ( chlorophyll derivatives in plants, blood derivatives in animals) are found in  all  organic matter; they are also found in many petroleums . Presence of porphyrins also mean that  anaerobic conditions must have developed early in the formation process because porphyrins are easily and rapidly oxidized and decompose under  aerobic conditions . Additionally, low Oxygen content also implies a reducing environment. Thus there is a high probability that petroleum originates within an anaerobic and reducing environment. Nearly all petroleum occurs in sediments that are primarily of marine origin. Petroleum contained in non-marine sediments probably migrated into these areas from marine source materials located nearby. Furthermore, temperatures in the deeper petroleum reservoirs seldom exceed 300 o F (141 o C). But temperatures never exceeded 392 o F (200 o C ) where porphyrins are present because they are destroyed above this temperature. Therefore the origin of petroleum is most likely a low-temperature phenomenon. Time requirements may be less than 1 Ma years ; this is based on more recent oil discoveries in  Pliocene sediments . . However, physical conditions on the Earth may have been different in the geologic past and therefore it may have taken considerably more time to develop liquid petroleum. 7

8. PETROLEUM SYSTEM Magoon and Dow (1994) defined petroleum system as a unifying concept that encompasses all of the distinct elements and processes of petroleum formation and all genetically related petroleum that originated from one pod of active source rock and occurs in shows , seeps , or accumulations : Essential elements : Source rock, Reservoir rock, Seal rock, Overburden/cover rock Processes : T rap formation, G eneration – Migration – Accumulation of hydrocarbon The petroleum system concept infers that, by reason of the provenance of genetically related oil and gas accumulations, migration pathways must exist, either now or in the past, connecting the provenance with the accumulations. Using the principles of petroleum geochemistry and geology, this fluid system can be mapped in the geosphere to better understand how and when it could charge undiscovered traps . In order to properly discuss the petroleum system, it must be named. It is a compound name that includes the source rock in the pod of active source rock, the reservoir rock containing the largest volume of petroleum, and the level of certainty of a petroleum system. If the source rock and the major reservoir rock have the same name, then only one name is used. The level of certainty is the measure of confidence that petroleum from a series of genetically related accumulations originated from a specific pod of active source rock. Three levels are used: Known, Hypothetical, Speculative Depending on the level of geochemical, geological and geophysical evidence. 8

9. SOURCE ROCK A source rock can be broadly defined as any fine-grained, organic-rich rock that is capable of generating petroleum, given sufficient exposure to heat and pressure. Its petroleum generating potential is directly related to its volume, organic richness and thermal maturity. Source rocks result from a convergence of physical, biochemical and geologic processes that culminate in the formation of fine-grained sedimentary rocks containing carbon- and hydrogen-rich organic matter . The amount and type of organic material incorporated into a source rock are controlled, in part, by environmental and depositional conditions. Source rocks form where environmental conditions support biologic activities that produce large quantities of organic matter , where depositional conditions concentrate this matter and where post-depositional conditions permit its preservation. 9

10. 10 Organic matter in the water column.

11. Organic content is controlled largely by bio logic productivity , sediment mineralogy and oxy genation of the water column and sediment. Biologic contributions to organic content range from hydrogen-poor woody fragments to hydrogen- rich algal or bacterial components . From these, a variety of organic compounds may be created. Oxygen in the water column supports biologic productivity of organic matter but also promotes biodegradation and oxidation . The matter can also be altered by physical abrasion or chemical changes in water E h and pH. Once this matter settles to the bottom, bacteria, worms and other bottom feeders take in what they can metabolize, converting some of it to simple molecules. The net result of biodegradation and oxidation is a reduction in organic richness , leaving only relatively resistant organic materials to be incorporated into the sediment. Within this depositional setting , oxygen and energy levels are perhaps the most critical aspects controlling the concentration and preservation of organic matter in the sediment. Oxygen-depleted, or anoxic , sediments provide the best media for preserving organic matter and also restricting the activity of bottom feeders . Anoxic conditions are evidenced by source rocks that have minute laminations, or varves . 11

12. Because quiet waters reduce the exchange of oxygen and organic matter , they create an envi ronment in which anoxic conditions can exist. These low-energy environments permit the deposition of finer-grained sediments as well. Thus, there is a relationship between grain size and organic content in source rocks. Source rocks do not form in high-energy environments —such as beaches or sand bars —where sands are typically deposited. Mineralogy also plays an integral role in source rock development. Minerals, transported and precipitated in the sediment, can react with organic compounds and ultimately dilute the rel ative concentration of organic matter within the sediment. This dilution may affect a source rock’s capacity to generate and expel petroleum. Although many organic-rich source rocks are argillaceous, carbonates (typically marls) can also make excellent source rocks. Some carbonates may contain as much as 10% to 30% total organic carbon (TOC), unlike shales , which may contain less than 5%. In general, quality source rocks —whether carbonate or shale—share a number of common characteristics. They form in anoxic , or highly reducing, environments, are generally laminated , have moderate to high TOC and contain organic matter exemplified by atomic hydrogen/carbon ratios exceeding 1.2 . 12

13. Organic Matter Types Given sufficient heat, pressure and time , the sediment lithifies and the organic matter contained within source rocks transforms into kerogen . Kerogen can be classified into four types , based on provenance , as indicated by specific macerals . It can also be classified on the basis of hydrogen, carbon and oxygen content . Each type has a distinct bearing on what kind of petroleum, if any, will be produced. Type I kerogen is generated predominantly from lacustrine environments and, in some cases, marine environments . It is derived from algae, plankton or other matter that has been strongly reworked by bacteria and microorganisms living in the sediment. Rich in hydrogen and low in oxygen , it is oil prone but, depending on its stage of thermal evolution, can also produce gas. Responsible for less than 3% of the world’s oil and gas reserves, Type I kerogens are not common. Type II kerogen is typically generated in reducing environments found in moderately deep marine settings. It is derived primarily from the remains of plankton that have been reworked by bacteria . Rich in hydrogen and low in carbon, this kerogen can generate oil or gas with progressive heating and maturation. Certain depositional envi ronments promote increased incorporation of sulfur compounds , resulting in a variation known as Type II-S kerogen . The significance of this type is that generation of oil starts much earlier , thought to be caused by kinetic reactions involving sulfur-bearing compounds. Type III kerogen is derived primarily from ter rigenous plant debris , which has been deposited in shallow to deep marine or nonmarine environments . Type III kerogen has lower hydrogen and higher oxygen content than Types I or II; consequently, it tends to generate dry gas . Most coals contain Type III kerogens . Type IV kerogen is derived from residual organic matter found in older sediments that have been reworked after erosion. Prior to final deposi tion, this kerogen may have been altered by sub- aerial weathering, combustion or biologic oxidation in swamps or soils. This type of kerogen has high carbon content and is hydrogen poor . Considered a form of dead carbon , it has almost no potential for generating oil or gas . 13

14. 14 Kerogen type Source material General environment of deposition I Mainly algae Lacustrine setting II Mainly plankton, some contribution from algae Marine setting III Mainly higher plants Terrestrial setting IV Reworked, oxidized material Varied settings

15. The thermal maturation process can be divided into three stages : Initially, the sediment is subjected to diagene sis . In its broadest sense, this term encom passes all natural changes in sediments occurring from the moment of deposition until just before the onset of significant thermal alteration processes. For source rocks, however, this stage is characterized by alteration of organic matter , typically at temperatures below about 50°C [122°F]. During diagenesis, oxidation and other chemical processes begin to break down the material . If deposited under anoxic condi - tions , this material may be converted by methanogenic bacteria into dry gas . With increasing temperatures and changes in pH, the organic matter is gradually converted to kerogen and, in lesser amounts, bitumen . The source rock matures with increasing heat, and it undergoes catagenesis . During this stage, petroleum is generated as temperature increases to between 50°C and 150°C [122°F and 302°F], causing chemical bonds to break down within the kerogen. Within this oil win dow , Type I and II kerogens produce both oil and gas , while Type III kerogens produce mainly hydrocarbon gas . Further increases in burial depth, temperature and pressure force the source rock into the upper part of the gas window , where secondary cracking of the oil molecules produces wet gas containing meth ane, ethane, propane and heavier hydrocarbons . Metagenesis marks the final stage, in which additional heat and chemical changes convert much of the kerogen into methane and a carbon residue . As the source rock moves farther into the gas window , late methane, or dry gas , is evolved, along with nonhydrocarbon gases such as carbon dioxide [CO 2 ], nitrogen [N 2 ] and hydrogen sulfide [H 2 S]. These changes take place at temperatures ranging from about 150°C to 200°C [302°F to 392°F]. 15 Thermal Transformation of Organic Matter

16. 16 Thermal Maturation of organic matter

17. Types of Source Rocks These thermal transformation stages have a direct bearing on source rock maturity. Thus, giving rise to the following types of source rocks: Thermally immature or potential source rocks - These are source rocks that have been altered by diagenesis but are yet to be exposed to sufficient heat to thermally generate petroleum. Thermally mature or effective source rocks – These are source rocks that are (or were) in the oil window, and have been subjected to thermal processes necessary to produce petroleum and are actively generating petroleum. Thermally postmature or spent source rocks – These are source rocks that have entered the gas window and have already generated petroleum; in so doing they have exhausted all hydrogen necessary for further oil or gas generation. Although maturation is largely related to increasing burial depths caused by continual sedimentation within a basin , it can also be locally or regionally influenced by heat flow arising from crustal tectonics , proximity to igneous bodies and natural radioactive decay within the crust. The geologic processes that control subsidence and uplift also affect maturation within a basin. Maturation can be interrupted if the basin is subjected to uplift, only to continue when sub sidence resumes . 17

18. Migration of Petroleum There are two types of migration:  primary  and  secondary . Primary migration refers to the movement of hydrocarbons from source rock into reservoir rock . Secondary migration refers to the subsequent movement of hydrocarbons within reservoir rock . This occurs when petroleum is clearly identifiable as oil and gas although the gas may be dissolved in the oil. Buoyancy of the hydrocarbons occurs because of differences in densities of respective fluids and in response to differential pressures in reservoir rock.  There is considerable disagreement regarding why and how primary migration occurs and the theories are many and varied; it is the last problem in petroleum geology to be solved. Most scientists agree that the vast majority of petroleum hydrocarbons are generated by thermal processes from organic material contained in source rocks. There are 3 primary observational evidence that suggests that the hydrocarbons migrated into reservoir rocks at considerable depth below the surface and at some time after burial: oil and gas occur in pores and fractures in host rock (reservoir rock) that formed after its transformation (lithification) into solid rock, oil & gas are trapped at the highest point in a permeable rock unit which necessitates lateral and upward migration through a reservoir rock, and oil, gas, and water occur together in a stratified relationship in porous and permeable reservoir rock. Stratification requires freedom to migrate laterally and vertically within a porous and permeable reservoir rock. All of the observations suggest that hydrocarbons migrate into reservoir rocks at considerable depth below the surface and at some time after burial. But these three observations create a major paradox to resolve. 18

19. Oil and gas are trapped in permeable reservoir rock, yet the source rock from which they came from are shale (clay) that is essentially impermeable. So how did the fluids move from the source rock to the reservoir rock? Furthermore, why does it leave the source rock and how? There are a number of ideas, but no definitive answers. One idea is that it is squeezed from the source material (organic rich clay) before compaction destroys permeability, but there are a couple of problems with this. First, most water (pore water) expulsion by compaction occurs in the upper 2 km of burial before hydrocarbons have a chance to form. Second, this compaction occurs at temperatures lower than that required for the creation of hydrocarbons. Compaction reduces permeability, yet permeability is needed to move liquids and gases through a material. If compaction reduces permeability, how can you push a fluid or gas through it? The answer lies in the fact that there are two types of water in clays: pore water which is water trapped in sediments at time of deposition, and structured water or water bonded to the layers of the clay minerals. The process of hydrocarbon expulsion works something like this. Organic-rich clay is deposited on the sea floor as  montmorillonitic -rich muds. The expulsion of water occurs in two phases at different periods of time: The early phase is the time frame in which pore water is removed by compaction that occurs in upper 2 kilometers (km) of sediments. A second phase occurs later in time where structured water is de-linked from the clay lattice and expelled by further compaction. This phase occurs at deeper depths and at temperatures that vary from 100 - 110 o  C. 19

20. The second phase is also a time where compaction causes the collapse of the montmorillonite lattice which forms a new clay mineral called illite . The whole process of water expulsion is called clay dehydration . But how are the hydrocarbons expelled from the sediments? The exact physical and chemical processes are not clear, but all theories postulate that oil migrates from the source bed as a discrete oil phase . The hydrocarbons are attached to the structured water in the montmorillonite clay lattice. The structured water is de-linked from the clay lattice and expelled during the second phase of expulsion. Upon further dehydration, hydrocarbons become detached from the structured water before  illite  is formed and are in a free-phase as discrete hydrocarbons. But there are some other important factors besides dehydration. Differential pressure creates gradients and therefore induces flow of the discrete hydrocarbons, temperature may heat the hydrocarbons which induces them to move more freely in the subsurface, and presence of wetting agents ( natural soaps ) enhance solubility of hydrocarbons which also aids in their migration elsewhere. Also important in expulsion of hydrocarbons from the sediments are micro fractures in the source rocks because they create pathways for migration, presence of gases . Natural gas goes into solution at great depths because of pressure, but condenses and becomes a free-phase component at shallow depths. And the presence of other gases such as CO 2  lowers viscosity thus increasing mobility. 20

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22. HYDROCARBON TRAPS Because oil and gas are mobile fluids , they are able to migrate from one place to another in their natural environment (reservoir). If they are to become collected into an accumulation capable of economic exploitation , their capacity for migration has to be arrested somehow. The arresting agent is called a trapping mechanism . A trap is simply any geometric arrangement of strata that permits the accumulation of oil or gas or both, in commercial quantities . A trap therefore has two functions: It receives the hydrocarbons It obstruct their escape 22

23. Types of Traps Two types of petroleum traps are recognised: structural and stratigraphic . Structural traps are formed by deformation of reservoir rock , such as by folding or faulting . Stratigraphic traps are formed by deposition of reservoir rock , such as river channel or reef, or by erosion of reservoir rock , such as an angular unconformity Structural Trap Structural trap is a type of geological trap that forms as a result of changes in the structure of the subsurface, due to tectonic, diapiric , gravitational and compactional processes . These changes block the upward migration of hydrocarbons and can lead to the formation of a petroleum reservoir. Structural traps are the most important type of traps as they represent the majority of the world’s discovered petroleum resources. The three basic forms of structural traps are the anticline trap, the fault trap and the salt dome trap. 23

24. 24 Principal types of hydrocarbon traps

25. Anticline/Dome Trap An anticline or dome may form in an area of the subsurface where the strata are folded or have been pushed into forming a domed shape. If there is a layer of impermeable rock present in the anticline or dome shape, then hydrocarbons can accumulate at the crest until the anticline or dome is filled to the spill point (the point where hydrocarbons can escape from the trap). This type of trap is by far the most significant to the hydrocarbon industry. These traps are usually long or oval domes of land that can often be seen by looking at a geological map or seismic sections. Fault Trap This trap is formed by the movement of permeable and impermeable layers of rock along a fault line. This is formed when a permeable reservoir rock is faulted such that it is now adjacent to an impermeable rock, hence, preventing hydrocarbons from further migration. In some cases, there can be an impermeable substance smeared along the fault line (such as clay) that also acts to prevent migration. This is known as clay smear. Salt dome Trap A mass of salt deposit is pushed up through clastic rocks due to their greater buoyancy, eventually breaking through and rising towards the surface. This salt is impermeable and when it crosses a layer of permeable rock, in which hydrocarbons are migrating, it blocks the pathway in much the same manner as a fault trap. This is one of the reasons why there is significant focus on subsalt imaging, despite the many technical challenges that accompany it. 25

26. 26 Anticline trap Fault Trap Salt dome Trap

27. Stratigraphic Traps Stratigraphic traps are formed as a result of lateral and vertical variations in the thickness, texture, porosity or lithology of the reservoir rock . Examples of this type of trap are an unconformity trap, a lens trap and a reef trap .   Two main groups are recognized: Primary These are stratigraphic traps that result from variations in facies that developed during sedimentation . These include features such as lenses, pinch-outs, and appropriate facies changes . Secondary These are stratigraphic traps that result from variations that developed after sedimentation , mainly because of diagenesis . These include variations due to porosity enhancement by dissolution or loss by cementation . Paleogeomorphic traps are controlled by buried landscape. Some are associated with prominences (hills); others with depressions (valleys). Many are also partly controlled by unconformities so are also termed unconformity traps . 27

28. 28 Staratigraphic Traps

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30. RESERVOIR FLUIDS Reservoir fluids fall into three broad categories: i . aqueous solutions with dissolved salts ii. liquid hydrocarbons iii. gases (hydrocarbon and non-hydrocarbon) In all cases their compositions depend upon their: source history present thermodynamic conditions . Their distribution within a given reservoir depends upon: the thermodynamic conditions of the reservoir the petrophysical properties of the rocks the physical and chemical properties of the fluids themselves 30

31. Fluids Distribution i . Layered Fluid Occurrence 1. Gas less dense (on top) - Oil - Water Most Dense (on bottom) 2. Oil-Water Table Contact vs. Gas-Water Table Contact ii. Interstitial Water 1. Distribution of water in pore spaces throughout reservoir a. Range 10 – 30 %, up to 50% iii. Oil-Gas-Water Separation Process is necessary as part of well-head processing 31

32. Physical And Chemical Nature Of Reservoir Fluids i . Dominant Subsurface Fluids within 15,000 – 20,000 ft of Earth Surface 1. Water – most abundant, predominant 2 . Oil and gas – relatively low volumes comparatively ii. Water-Oil-Gas mixtures and chemical properties vary according to regional geology iii. Oil and Gas 1. Relatively insoluble in water; gas and oil are miscible with one another - Gas dissolution / exsolving from solution 2. Lower density than water 3. Buoyant fluids 4. NAPLs – Non- Aqueous Phase Liquids 32

33. A. FORMATION WATER Oil Field Brines / Connate Water i . Salinity Ranges (parts per thousand, g solute per L of water) 1. Ocean Water average ~35 ppt (3.5%) 2. Meteoric Water / “Fresh Water” < 1 ppt 3. Oil Field Waters: ranges up to ~300 to ~500 ppt (30-50%) 4. >salinity with > depth and residence time in subsurface ii. Brine Water Salinity and Chemical Composition Greatly Varies with Geology of the Oil Basin iii. Sources of Salinity 1. Long residence times in formation, dissolution of reservoir framework 2. Ion exchanges with clay minerals 3. Evaporation / concentration of formation waters in depositional environment 4. Original composition of marine waters at time of deposition 33

34. B. CRUDE OIL a. Overview i. Crude constitute small percentage of total fluids in reservoir rocks (dominated by water) ii. Crude Oil = liquid oil hydrocarbons 1. Variable in composition and physical properties 2. Dependent upon source rock composition and geologic history 3. Mixtures with dissolved gas and free gas 4. Soluble in organic solvents iii. Solid petroleum b. Measurement i . Volume measurements: 1. barrels, tons, acre-feet 2. 1 barrel = 42 gallons (US); avg.wt . = 310 lbs 3. Abbreviation for “barrel” = bbl c. Chemical Properties i . Comprised of over 200 organic compounds ii. Gas, oil, asphalt = primarily hydrocarbons, with minor sulfur, nitrogen, oxygen iii. Molecular Composition – complex variety of over 200 organic compounds due to the versatile nature of carbon bonding with 4 electrons in outermost valence shell 34

35. Average Elemental Composition by % Weight Element Crude Oil Asphalt Natural Gas Carbon 82-87 80-85 65-80 Hydrogen 12-15 8.5-11 1-25 Sulfur 0.1-5.5 2-8 tr – 0.2 Nitrogen 0.1-1.5 0-2 1-15 Oxygen 0.1-4.5 -- -- 35

36. 1. Hydrocarbon Compounds in Petroleum a. Paraffins ( alkanes ) – saturated hydrocarbons, all C-H bonds satisfied by single covalent bonds i . General formula: C n H 2n+2 1. n < 5 gaseous at normal temp and pressure 2. n ranging from 5-15 liquid at surface temp. and pressure 3. n > 15 solid waxes and viscous liquids 4 . Common Examples in Petroleum a. Methane CH 4 (simplest) b. butane C 4 H 10 c. Pentane C 5 H 12 d. Hexane C 6 H 14 e. Octane C 8 H 18 ii. Stable bonds, less reactive hydrocarbons iii. complex variability of bonding combinations in hydrocarbon family iv. box-chain hydrocarbon molecules 36

37. b . Napthenes ( cycloparaffins ) i . General formula: C n H 2n ii. Liquid at normal temperatures and pressures iii. Branching ring hydrocarbon molecules iv. Common E.g., in Petroleum: Cyclopentane (C 5 H 10 ) c. Aromatics (benzene series) i . Ring hydrocarbon molecules ii. common E.g. in petroleum: benzene C 6 H 6 d. Complex Residues – Asphaltics i . High molecular wt., solid to semi-solid ii. Petroleum residue iii. High in nitrogen, sulfur, oxygen 37

38. 2. Mixed compounds / other constituents Crude oil contains low percentages of N, S, O, trace metals: a. Sulfur occurs as free S or dissolved hydrogen sulfide gas H 2 S “sour crude”, degrades quality of petroleum for use i . <0.5% low sulfur crude ii. >0.5% high sulfur crude b. Nitrogen – low amounts in crude, inert constituent in natural gas c. Oxygen – minor component d. Organic matter, fossil materials, microscopic, mixed as solids in crude oil Average Organic Composition of Crude Oil Molecular Type Weight Percent Paraffins 25 Napthenes 50 Aromatics 17 Asphaltics 8 Total 100 38

39. d. Physical Properties of Crude Oil i . Density American Petroleum Institute ( API) Gravity Index Classification a. High API gravity values = low specific gravity, Low API gravity values = high specific gravity b. API 10 = density of water, API values > 10 = floaters; API values < 10 = sinkers API GRAVITY INDEX EQUATION: Degrees API = (141.5/ S.G. at 60 o F) - 131.5 where S.G. = specific gravity of oil sample c. API Gravity Classification of Oils Light Oil – API > 31.1 Medium Oil – API between 22.3 and 31.1 Heavy Oil – API < 22.3 Extra Heavy Oil – API < 10.0 d. API Gravity Range of Crude Oil on average 15-57 degrees i . Varies according to source region, geology 39

40. ii. Volume – pressure dependent 1. Gas commonly dissolved in oil within reservoir at depth, under high pressure 2. Extraction of oil results in increase pressure and temperature at surface a. Gas exsolves from oil as it reaches surface, net fluid volume decreases in remaining liquid (“inflated oil”) b. 1 barrel oil in subsurface = 0.8 barrel at surface (shrinkage factor) 3. > Depth, > Pressure, > capacity for dissolution of gas in oil iii. Viscousity 1. Measure of fluid resistance to flow measured in centipoise ( cP ). Water has a viscosity of 1 cP - High viscousity – thick liquid, highly resistant to flow; vice versa a. Viscousity is temperature dependent; > temp < viscousity, < temp > viscousity b. Gas also influences crude viscousity – > gas content < viscousity ; < gas content > viscousity 40

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43. Abnormal Formation Pressure A subsurface condition in which the pore pressure of a geologic formation exceeds or is less than the expected, or normal, formation pressure. When impermeable rocks such as shales are compacted rapidly , their pore fluids cannot always escape and must then support the total overlying rock column , leading to abnormally high formation pressures. Excess pressure, called overpressure or geopressure , can cause a well to blowout or become uncontrollable during drilling. Severe underpressure can cause the drillpipe to stick to the underpressured formation. 43

44. RESERVE ESTIMATION Reserve and Resource: Resources are accumulations of anything which is both useful and accessible to mankind. The Earth sciences are not directly concern with such renewable resources as timber, fish. They are directly concern with such apparently renewable resources as water, soil, and geothermal power. Petroleum geologist is concern with nonrenewable resources, formed by natural processes over time spans enormously long by comparison with those of human activities. Reserves are that portion of an identified resources that is available now by being economically recoverable under existing technological conditions. Undiscovered Inferred Indicated Measured (proven) 44

45. Requirements for Reserve Estimation of Oil or Gas: Useful estimations of oil and gas reserves in a pool or field are impossible until several strategically spaced (appraisal) wells are drilled. These wells must establish three aspects of the overall shape and size of the deposit: the elevation of the top of the deposit in its trap The elevation of the oil/water or gas/oil or gas/water interface The approximate outline of the trap in plan All other factors necessary for the calculation are measured or estimated from materials recovered from these initial wells. 45

46. The calculation of oil reserves involved three steps: STEP 1. The volume of the reservoir rock between the highest point in the trap and the level of the bottom water. This is simply: Vol of Res. = the accessible area X the av. Thickness of saturated rock There are several cautions: The area must be conservatively planimetered within the structural closure as it is believed to be established at the time of the estimate. If the legal measuring system is non-metric or metric but not expressed in SI units, the appropriate units must be used. Only that portion of the trap area accessible to and drainable by wells on the allowed well spacing should be included. STEP 2. The porosity ( ф ) is determined from cores , or calculated from neutron, density, or sonic logs . Some of the pores will be occupied by water (the irreducible water saturation S w ). S w is calculated from Archie’s formular . 46

47. STEP 3 . How much of the oil or gas content of the reservoir will be recovered by the mechanism to be employed? This depend on the viscousity of the oil, the porosity of the rock to oil, and the GOR (gas-oil ratio) as well as on the mechanics of the production system (Pumping, pressure maintenance). The recovery factor , eg ., for a heavy oil may be only 10-15% even with secondary recovery techniques. The figure used in the initial calculation should not be higher than about 35% unless deliverability of the reservoir has been seen to be exceptional. The shrinkage factor, If the reservoir GOR is significant, the oil will shrink when it is brought to the surface because its gas content will bubble off. The shrinkage factor (commonly 15-30%) converts the volume of oil in the reservoir to the volume of stock-tank oil (STO); It is expressed by a factor <1 ( eg ., 0.82). Alternatively, the factor used may be the reciprocal of the formation volume factor (FVF) , which converts STO to reservoir oil and is therefore a number slightly greater than unity ( eg ., 1.22). Shrinkage is calculated from the temperature, pressure and GOR of the oil (some of the shrinkage is due to cooling of the oil on leaving the reservoir to the surface); the volume is standardised as that at 15 o C (60 o F ). Recoverable STO = (A x h x ф x S o x R)/FVF where, A – area; h – thickness; ф – porosity; S o - oil saturation; R – recovery factor; FVF – shrinkage factor 47

48. RESERVOIR ENERGY AND DRIVE MECHANISM SOLUTION GAS DRIVE/GAS EXPANSION/DISSOLVED GAS DRIVE/DEPLETION DRIVE . This mechanism makes use of the energy of the gas in solution in the oil. This solution gas reduces the oil’s viscosity and surface tension , facilitating its movement through the reservoir. As reservoir pressure drops, the gas expands, driving the oil in the direction of the pressure gradient (towards the well bore). When the reservoir pressure is reduced to the saturation pressure throughout the reservoir, free gas bubbles out of solution, forming a secondary free gas cap. This gas has little help to production, because it simply occupies space vacated by oil. The relative permeability of the reservoir to oil declines rapidly early in the withdrawal history. Fluid pressures also decline rapidly; in general about 50% of the reservoir pressure has been dissipated by the time the pool has yielded 30-40% of its ultimate yield. The GOR (Gas Oil Ratio) increases sharply and the well becomes primarily a gas well. Gas drive alone seldom recovers more than 20-25% of oil in place; recovery from carbonate reservoirs is unlikely to be higher than 20% and may be as low as 5%. 48

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50. Gas Cap Drive A free gas cap may exist in the reservoir from the outset, containing the excess of gas beyond that required to saturate the oil at the reservoir T and P. The gas expands as the oil is withdrawn, exerting downward pressure on the oil and providing an effective recovery mechanism. Production declines continuously from the beginning but not so rapidly as under depletion drive. Allied with good permeability, high rates of oil production may be maintained for years, eventually recovering between 30-75% of oil in place. GOR remain low but increase as the rate of oil extraction declines, and eventually most of the production becomes gas. Active Water Drive Virtually all oil and gas pools contain either bottom water or edge water or both. If new water can enter this water column in the reservoir, from a recharge area beyond the bounds of the pool, its movement along the hydrodynamic pressure gradient will maintain the reservoir pressure- provided that the entry of new water is at a rate comparable with the rate of withdrawal of the hydrocarbons. The moving water sweeps through the reservoir below or behind the hydrocarbons, flushing them out of the pore space and towards the wells. Under favourable circumstances the recovery may be the highest among all drive processes, from 36-80% of oil in place. 50

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53. Gravity Drainage Gravity acts on reservoir fluids whatever their total volumes or their relative proportions may be. In some pools, especially those having originally been produced under solution gas drive, a high proportion of the original oil in place – say 75% - may be left in the reservoir when its pressure has fallen below the effective minimum for further recovery. At the top of the reservoir the pressure may be reduced effectively to atmospheric. The secondary gas cap has disappeared from above the oil, and if there is no water drive from below, the remaining oil is not acted upon by any effective force except that of gravity. It therefore seeps downwards through the reservoir, eventually finding the lowest level the permeability can allow. If wells are completed at depths below the earlier oil/water inter-phase, or beyond the earlier down-dip limits of the pool, the oil that has seeped downwards can be recovered by pumping. The mechanism is not a “drive” because no moving agent is affecting the oil. Gravity creates a drainage of the reservoir; the whole “drive” is artificially exerted from the surface. In the absence of bottom water, gravity drainage may eventually recover practically all the oil in a pool, greatly prolonging the pool’s productive life. 53

54. Combinations Drive Many fields, perhaps, are acted upon by more than one type of drive mechanism. The most commonly met combination of drives is solution gas drive (with or without a small gas cap) augmented by a weak water drive. The most efficient combination drive is that associating a free gas cap and active water drive. Many fields in the interior basins of North America, in the North Sea, in the North Africa, and Indonesia are blessed with this combination. 54

55. NIGER DELTA GEOLOGICAL SETTING The Tertiary Niger Delta is situated at the intersection of the Benue Trough and the South Atlantic Ocean where a triple junction developed during the separation of the continents of South America and Africa in the Late Jurassic. Subsidence of the African continental margin and cooling of the newly created oceanic lithosphere followed this separation in Early Cretaceous times. Marine sedimentation took place in the Benue Trough and the Anambra Basin from mid-Cretaceous onward. The Niger Delta started to evolve in early Tertiary times when clastic river input increased. Generally, the delta prograded over the subsiding continental-oceanic lithospheric transition zone, and during the Oligocene spread onto oceanic crust of the Gulf of Guinea. The weathering flanks of out-cropping continental basement sourced the sediments through the Benue-Niger drainage basin. The delta has since Paleocene times prograded a distance of more than 250 km from the Benin and Calabar flanks to the present delta front. Thickness of sediments in the Niger Delta averages 12 km covering a total area of about 140,000 km 2 . 55

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58. Stratigraphic Framework The stratigraphic sequence of the Niger Delta comprises three broad lithostratigraphic units namely, a continental shallow massive sand sequence – the Benin Formation, a coastal marine sequence of alternating sands and shales – the Agbada Formation, and a basal marine shale unit- the Akata Formation. THE AKATA FORMATION The Akata Formation consists of clays and shales with minor sand intercalations. The sediments were deposited in prodelta environments. The sand percentage here is generally less than 30%. Its thickness ranges from 600-6000 m. 58

59. THE AGBADA FORMATION The Agbada Formation consists of alternating sand and shales representing sediments of the transitional environment comprising the lower delta plain (mangrove swamps, floodplain, marsh) and the coastal barrier and fluvio-marine realms. The sand percentage within the Agbada Formation varies from 30 to 70%, which results from the large number of depositional offlap cycles. A complete cycle generally consists of, thin fossilferous transgressive marine sand, followed by an offlap sequence which commences with marine shale and continues with laminated fluviomarine sediments, followed by barriers and/or fluviatile sediments terminated by another transgression. Thickness here varies between 300 and 4,500 m. THE BENIN FORMATION The Benin Formation is characterized by high sand percentage (70–100%) and forms the top layer of the Niger Delta depositional sequence. The massive sands were deposited in continental environment comprising the fluvial realms (braided and meandering river systems) of the upper deltaic plain. This unit may reach up to about 2,100 m thick. 59

60. Structural Geology The total delta sequence is formed by a series of sedimentary belts which reflect the depocentres succeeding each other in time and space by southward progradation. Each depobelt is bounded by major structure-building faults. Five major depobelts, 30-60 km wide each, have been distinguished: Northern Delta Greater Ughelli Central Swamp Coastal Swamp Offshore The most striking structural features of the Tertiary Niger Delta are the large synsedimentary growth faults, roll-over anticlines and shale diapirs which deformed the delta complex. A large number of the over 150-400 oil and gas fields are associated with roll-over anticlines with smaller number associated with stratigraphic traps . 60

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64. PETROLEUM SYSTEM The marine shales of the Akata Formation are generally over-pressured (under-compacted) and are considered to be the main source of the hydrocarbons found throughout the delta. The paralic sequence of the Agbada Formation with the alternating sand and shale layers contains nearly all the petroleum accumulations. It plays, however, a minor role as a source formation. The continental Benin Formation is acting as a cover rock. 64

65. RESERVOIR SANDS The reservoir quality of the Agbada sands is strongly dependent on the depositional environment and the depth of occurrence. Many reservoirs consist of a single barrier bar or point bar development. Reservoir sands thicker than 15 m are usually of a complex nature, consisting of superimposed sands deposited in the same or different sedimentary environments. Commonly 2 or 3 barrier bars developed one on top of the other without the intercalation of a significant marine shale. Laterally, many reservoirs are heterogeneous. A common occurrence is a barrier bar cut by a distributary channel fill at the same stratigraphic level. SOURCE ROCKS The Akata shale has been deposited under anoxic conditions on the continental slope in front of the delta where the nutrient supply for planktonic organisms must have been plentiful. A delta-wide study of shale samples indicated that, the upper part of the Akata Formation can be considered as a mature source rock, except for the most eastern part of the delta. Although many shale samples from the lower part of the paralic sequence also have source rock characteristics, but are generally immature. 65

66. MIGRATION Many authors have emphasized the role of the growth faults as migration avenues for hydrocarbons from the under compacted Akata shales into the Agbada reservoirs. At the level of the Akata Formation, the major growth faults offset a thickness of up to several thousand feet of over-pressured shale against paralic sediments in the downthrown block. The sands juxtaposed against over-pressured formations are the only downthrown block reservoirs which occasionally have hydrocarbon accumulations trapped against growth faults. From the conductive fault zones the hydrocarbons appear to flow into the downthrown blocks only. Other routes may include migration path along regional flanks, i.e. from a seaward facies change up-dip into the south flank of a rollover structure. 66

67. TRAPPINGS Structural Role-over anticlines and associated growth faults form the major trapping mechanism in the Niger Delta. Stratigraphic Minor stratigraphic trappings occur also in many fields as a result of lateral facies changes. Some stratigraphic trappings are associated with clay filled gullies (canyons). Others resulting from a combination of pinching out of sands and up-warping against the western flank of the Abakaliki High. 67

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69. SOME OIL AND GAS FIELDS The Niger Delta, offshore Dahomey Basin and some parts of the Anambra Basin, constitute currently the oil province of Nigeria. The Niger Delta oil province is rated the 12 th largest in the world with about 400 oil and gas fields of varying sizes. For the entire period of oil exploration and production in Nigeria, 49% of the exploration wells can be termed successful (575 discoveries from 1,182 exploration wells). Analysis of the discoveries shows that 3% of the fields are giants and represent 32% of the total reserves found. In retrospect, 40% of the discoveries represent smaller fields. Collectively, the giant fields produce in excess of 1 million barrels a day out of the nation’s total production of about 2.1 million barrels per day. A giant oil field is classified as a field with an estimated ultimate recoverable oil of more than 500 million barrels. The giant fields in Nigeria include Oso , Ubit , Assan , Meren , Abo , Bonga , Agbami , etc. The Bonga field is located 120 kilometers (75 miles) offshore and has a daily production capacity of 200,000 barrels of oil and 150 million standard cubic feet of gas. Most Nigerian oilfields produce 20,000–40,000 barrels per day. Nigeria’s average well produces 1,000 barrels a day. Those fields with estimated recoverable oil in place of 30 million barrels and less are termed “marginal fields” and are hardly further developed by the major operating companies. 69