Petroleum Field Appraisal
Oil and gas field appraisal is undertaken to determine the size and characteristics of a petroleum discovery. Those characteristics include the quantity of oil and/or gas present, the location of fluid contacts, the presence and distribution of baffles and barriers to fluid flow, and the quality of the reservoir. Data gathered during appraisal will be used to determine whether the field development is commercially viable, and if viable how the field should be developed.
Field appraisal links the discovery of petroleum in the exploration phase with the decision as to develop the discovery or not. Appraisal typically involves drilling more wells, each of which has a comprehensive data acquisition program. Appraisal may well involve acquisition of new seismic data. The aim of the process is to determine how much oil (standard barrels of oil initially in place, STOIIP) or gas is initially in place (gas initially in place, GIIP) for the discovery and determine how much of the petroleum fluid can be extracted economically, that is, the petroleum reserve for the field. During the process of appraisal, the expectation is that the range of uncertainty for the oil and or gas in place and thus potential reserves will be reduced. Petroleum discoveries offshore commonly require more appraisal than those onshore. This is because for offshore fields it is likely that a facility (platform, production vessel, or sea-bed well-head cluster) will be built or adapted to optimize anticipated production from the field when on plateau. Altering a platform after it has been installed to meet greater than expected production performance is expensive as is oversizing a facility. However, onshore it is commonly possible to modularize development without substantive extra cost, and hence, it may only be necessary to determine the minimum economic threshold for the field. Dromgoole and Spears (1997), Gluyas and Swarbrick (2004), Gluyas and Garrett (2005), and Morten et al. (2012) provide more information on the petroleum field appraisal.
When a field is discovered, the quantity and distribution of petroleum in the pool may be very poorly defined with only one point, the discovery well, known precisely. The relative positions and shapes of the bounding surfaces for the pool, top seal, any lateral or basal seals, and the fluid contacts (gas/water, oil/water, gas/oil) controls the gross rock volume and hence petroleum in place. Unlike most of the other properties such as net to gross, porosity and petroleum saturation which can vary between 0 and 1, gross rock volume does not have an upper defined boundary. This means that uncertainty in gross rock volume commonly has the largest impact on the uncertainty range for petroleum in place.
Most petroleum accumulations have spill points that correspond to the minimum depth (shallowest closing contour) at which there is a continuous seal (Fig. 1b), so precluding upward migration of the petroleum. For a simple four-way dip-closed structure, identification of the shallowest closing contour may be relatively simple. However, lateral pinchout of the reservoir may make identification of spill points difficult as may the presence of combination traps which combine both dip and fault closure. Fields may also be compartmentalized with different areas having different spill points and hence fluid contacts (see below), though this may be far from obvious during an appraisal campaign. In addition to drilling wells to determine the areal extent of the discovery, wells will also be drilled to determine fluid contacts: oil-water contacts, gas-water contacts, and gas-oil contacts.
Appraisal will also be used to determine the type and distribution of petroleum fluids in the pool. This may be oil, gas, both oil and gas or condensate. These terms refer to the phase of the fluid at the surface under what are known as standard conditions (25 °C and 1 atmosphere of pressure, STP). The fluids in the subsurface may be quite different. The hydrocarbon and indeed aqueous fluids may be sampled during flow testing of a well or alternatively there are wireline conveyed devices which are able to sample downhole at reservoir conditions.
Most oils in the subsurface contain dissolved gas. At depth the fluid is a single (liquid) phase, but as the oil comes to surface, gas will be exsolved in the same way that carbon dioxide exsolves from champagne when the cork is removed. The quantity of gas dissolved in oil can vary from zero at STP to thousands of cubic feet per barrel. The degree of gassiness of the oil is determined by a combination of the source rock type, its maturity, the migration process, as well as the pressure and temperature history of the final accumulation. Oils that contain either very little or no dissolved gases are commonly referred to as “dead oils.” This specifically refers to oils which fail to flow to surface without pumping or gas lift.
Gas accumulations are derived from either gas prone source rocks (e.g., coal, type III kerogen), high maturity oil sources (types I and II kerogen), near surface (typically <1 km) bacterial degradation of organic matter or by separation of oil and gas on a migration pathway. Appraisal is required to determine the composition of the gas. Gas accumulations are referred to as dry when the hydrocarbon phase consists overwhelmingly of methane (>95%). Some gases, typically those derived from oil prone sources, contain the higher homologues: ethane, propane, butane, and so on. In addition to determining the hydrocarbon composition of the gas, appraisal will be used to ascertain the calorific content of the gas. This will vary both with the hydrocarbon composition and the quantity of non-hydrocarbon gases which may also be present (typically one or more of nitrogen, carbon dioxide, hydrogen sulfide, helium plus traces of other gases).
Gas over oil accumulations occur where there is excess gas in the accumulation above that which can be dissolved in the oil. The gas will then occur as a gas-cap. Depending upon the composition of the petroleum and pressure and temperature of the accumulation, it may not be possible to identify a phase change between gas at the top of an accumulation and oil at the base. Such fluids are termed super critical; they are difficult to characterize during appraisal as each sample returned to surface appears of be different.
The term condensate refers to a petroleum fluid which is a gas at high temperatures in the accumulation but a liquid at surface. As with critical fluids, it may be difficult to assess during appraisal because of the phase change that occurs when the sample is brought to surface.
In addition to characterizing the petroleum fluids, appraisal will also address the composition of the underlying aquifer. In particular, the primary concern is to determine the dissolved salt content in the water. Oilfield waters can be anything from near fresh to salt saturated. The conductivity/resistivity of the water beneath a petroleum accumulation is commonly used to calibrate wireline and measurement while drilling tools such that when potential reservoir units with higher resistivity are encountered they can be interpreted in terms of their petroleum content (petroleum is nonconductive) since all petroleum accumulations contain some water in the pore space as well as oil or gas. In the absence of information from an underlying water-leg there is no baseline against which to compare the resistivity measurements made in the oil/gas leg.
A petroleum discovery may comprise a single body of petroleum with pressure communication throughout its length, width, and height. In such circumstances, it would be theoretically possible to produce using a single well. Indeed for high-quality gas reservoirs, a single well development is quite likely to be used, whereas the likelihood of low production rates in low-permeability gas reservoirs and poor sweep efficiency in oil reservoirs usually demands that more than one well is used.
Identification of barriers to fluid flow is a key part of an appraisal program and it may not be easy to do so. Static (geological) data are rarely definitive and while dynamic data (reservoir engineering) such as fluid pressure analysis well tests may prove compartmentalization, they are rarely sufficiently comprehensive to rule out compartmentalization altogether.
Large-scale faults can be mapped from seismic data but small-scale faults which are still sufficient to displace reservoir units may not be resolvable. Wire-line, logging while drilling, and core data may be used to identify vertical changes in lithology and on occasion faults and fractures. These same data may also be used to determine petroleum saturation in reservoir intervals and, for example, multiple oil water contacts in a single well would indicate barriers to vertical flow. Fluid pressure data collected from different intervals in a single well or different wells may demonstrate that barriers are present if all the data do not fall on a single pressure depth trend for the petroleum and water intervals. However, the presence of a single pressure depth trend for the petroleum intervals may not preclude compartmentalization that only becomes apparent when production begins. Well test data (pressure and flow rate) can be used to determine the presence of barriers and distance to them (though not direction). Geochemical analysis of fluids (petroleum and water) can also be used to demonstrate compartmentalization if there are spatial variations which cannot be explained by other processes (such as gravitational segregation in oils).
The key to successful identification of compartmentalization is to use combinations of the above data together with regional geological information: structural setting, gross depositional environments, and analogue data from adjacent fields.
Net to Gross and Net Pay
Determination of average porosity for a petroleum accumulation is a key step in the process of calculating petroleum in place. Typically measurements of porosity are made on 1 in. (2.5 cm) diameter plugs cut from core. Hundreds or thousands of measurements are usually made for each cored well. Porosity can also be determined from well logs that measure bulk density. These require calibrating to local data on the density of the grains that make up the rock and fluids that fill the pore space. Where high quality seismic data are available, it may also be possible to calculate porosity from these seismic data. Again such data need to be calibrated against measurements made on rock and fluid. The plug (centimeter), well log (decimeter to meter), and seismic (decameter to kilometer) methods all record porosity at different scales. The measurements made on plugs are the most accurate, but it is not possible to sample every cubic centimeter of a petroleum accumulation and hence these data are combined with the coarser scale measurements to yield an average porosity for the pay intervals in the accumulation, segment, or layer.
Permeability and Relative Permeability
Permeability data are derived from core analysis or from well tests. There has also been some success in measuring permeability using nuclear magnetic resonance (NMR) imaging (a well logging tool).
Permeability data are used in calculations of both net to gross (and hence petroleum in place) and petroleum reserves. A value of permeability is commonly used for a net sandstone or net pay cut off. For a light oil, this may be a few millidarcies or higher for more viscous oils. For gas, in conventional reservoirs, the cut-off commonly lies between 0.1 and 1 mD for offshore settings where low flow rates are likely to be uneconomic. Conventional reservoirs onshore may be ascribed a lower cut off as will tight gas sands and shale-gas accumulations.
Permeability data are used in combination with pay thickness (completion interval) and planned pressure drawdown to calculate well flow rates. Such derivative data ultimately become part of the reservoir and economic models from which reserves are calculated.
Up-scaling of permeability data from core plugs to well-test or flow unit intervals is difficult because reservoirs are heterogeneous and anisotropic and because average permeability of a large interval is not a simple arithmetic average of the plug-scale laboratory measurements. For sedimentary rock bedding, parallel permeability is likely to be at least one order of magnitude greater than bedding perpendicular permeability.
The proportion of petroleum in the pore space of reservoir (the balance being brine) is the petroleum saturation. For appraisal that proportion needs to be measured (from core or well logging) as does its variation across a field. Maximum petroleum saturation or gas may be as high as 90% and for oil maybe 80% but much lower saturations are possible. Lower saturations occur close to the oil or gas water contact and for intervals where clays are present. Clay minerals have charged surfaces that attract water molecules. Such bound water may not flow from the rock when the oil is produced. So in some instances, measured petroleum saturations may be as low as 50% but on test the reservoir can produce dry oil.
Formation Volume Factor and Gas Expansion Factor
Oils shrink when raised from the reservoir to surface because hydrocarbon gases are exsolved, yielding a gas:oil ratio (GOR measured in standard cubic feet per barrel). Typically, volatile oils have formation volume factors (FVF) up to about two. “Dead oils” with little gas may have a FVF just above one. The FVF may vary across an oil pool. This needs to be captured during appraisal.
Gases expand when brought to surface. The extent of the expansion depends upon the pressure of the accumulation. Under normal hydrostatic conditions, the gas expansion factor (GEF) of a gas accumulation at 3 km burial is around 200. Shallower accumulations have lower values and deeper ones higher values.
Petroleum in Place
Petroleum in place is simply the product of gross rock volume, net pay, porosity, and petroleum saturation. It is normally reported at surface (standard temperature and pressure) conditions derived by taking the subsurface volume and dividing by the FVF for oil or multiplying by the GEF for gas. The accuracy of the calculation will depend on the data available from the appraisal program. It is a normal practice to calculate a range for each of the input parameters and then calculate a deterministic minimum, most likely, and maximum oil/gas in place or use a Monte Carlo probabilistic simulation to do the same. Petroleum in place calculations are commonly repeated as appraisal progresses and the expectation for the uncertainty in the derived value will shrink as more data are gathered.
Calculation of petroleum reserves is the ultimate goal of the appraisal process. Not all the petroleum will be recovered and hence the recovery factor (RF) is always less than one (or less than 100%). The proportion recovered will depend upon the fluid properties (both the petroleum and the water), the rock properties (permeability and permeability architecture), development methods (well placement and development scheme in terms of primary, secondary, and tertiary recovery applied), and the expected economic cut-off when the cost to produced is less than the value of the petroleum produced. The recovery factor for oils is typically in the range 30–60% and that for gases 50–90%. Ahead of any development decision, the reserves will be calculated using a reservoir model based on from the geological model built from the data types reported above.
Petroleum field appraisal is a critical link between the discovery of oil and/or gas in the ground and an optimized, commercially viable development of a field. Inevitably, the seismic and well data available during appraisal will not be sufficient to fully define the discovery and uncertainties and risks will be carried into the development and production phases. Nonetheless, the aim of appraisal is to determine the economically recoverable reserves of oil and/or gas by understanding the size of the accumulation; distribution; quality and connectedness of the reservoirs; the distribution of contacts between gas and oil, oil and water, and gas and water; and the rates at which production wells will flow and decline. With these data, it should be possible to design the development scheme and to engineer within that scheme flexibility to deal with what will be unexpected outcomes of field development and production.
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