Reservoir Engineering I Jan. Sem 2025 PDF

Reservoir Engineering I, Jan. Sem. 2025 Open 1 Presentation Outline What have we learnt? Reservoir Engineering I, Jan. Sem. 2025...

Reservoir Engineering I, Jan. Sem. 2025 Open 1 Presentation Outline What have we learnt? Reservoir Engineering I, Jan. Sem. 2025 Lesson Outcomes Hydrocarbon Volumes Calculation (Introduction) Fluid Pressure Regimes Reservoir Temperature Summary What are we going to learn in next lecture? 2 2 1  At the end of this lecture students should be able Reservoir Engineering I, Jan. Sem. 2025 to explain the concept of overburden pressure, fluid pressure and grain pressure. to apply the concept of fluids pressure regimes in determining the fluids contacts. 3 3 Hydrocarbon Volumes Calculation  This section introduces the fundamental concepts for estimating the hydrocarbons in place. Reservoir Engineering I, Jan. Sem. 2025  The description of the calculation of oil in place concentrates largely on the determination of fluid pressure regimes and the problem of locating fluid contacts in the reservoir.  Primary recovery is described in general terms by considering the significance of the isothermal compressibilities of the reservoir fluids 4 4 2  Hydrocarbon Volumes Calculation Oil volume in the reservoir (oil in place) Reservoir Engineering I, Jan. Sem. 2025 Where, V = the net bulk volume of the reservoir rock. ϕ = the porosity, or volume fraction of the rock which is porous. Swc = the connate or irreducible water saturation and is expressed as a fraction of the pore volume. Normally 10−25% pore volume (PV). 5 5 Hydrocarbon Volumes Calculation Oil volume in the reservoir (oil in place) Reservoir Engineering I, Jan. Sem. 2025 Pore volume the total volume in the reservoir which can (PV) be occupied by fluids. Hydrocarbon pore volume (HCPV) the total reservoir volume which can be filled with hydrocarbons either oil, gas or both. 6 6 3  Hydrocarbon Volumes Calculation Stock tank oil initially in place (STOIIP) Reservoir Engineering I, Jan. Sem. 2025 Where, V = the net bulk volume of the reservoir rock. ϕ = the porosity, or volume fraction of the rock which is porous. Swc = the connate or irreducible water saturation and is expressed as a fraction of the pore volume. Normally 10−25% pore volume (PV). Boi = the oil formation volume factor, under initial conditions, the units reservoir volume/stock tank volume, usually, reservoir barrels/stock tank barrel (rb/stb). Note: A volume of Boi rb of oil will produce one stb of oil at the surface together with the volume of gas which was originally dissolved in the oil in the reservoir. 7 7 Hydrocarbon Volumes Calculation Reservoir Engineering I, Jan. Sem. 2025 The parameters ϕ and Swc are normally determined by petrophysical analysis. The net bulk volume, V, is obtained from geological and fluid pressure analysis. (a) Structural contour map of the top of the reservoir, and (b) cross section through the reservoir, along the line x-y 8 8 4  Fluid Pressure Regimes The total pressure at any depth, resulting from the combined weight of the formation rock and fluids, Reservoir Engineering I, Jan. Sem. 2025 whether water, oil or gas, is known as the overburden pressure. In the majority of sedimentary basins, the overburden pressure increases linearly with depth and typically has a pressure gradient of 1 psi/ft. Overburden pressure (OP) = fluid pressure (FP) + the grain or matrix pressure (GP) OP = FP + GP 9 9 Fluid Pressure Regimes Overburden pressure (OP) Total reservoir pressure at any depth: combined Reservoir Engineering I, Jan. Sem. 2025 weight of the formation rock and fluids (water, oil or gas). Increases linearly with depth and typically has a pressure gradient of 1 psi/ft. Balanced in part by the pressure of the grains of rock under compaction and the fluids pressure within pores (pore pressure). 10 10 5  Fluid Pressure Regimes Hydrostatic pressure The pressure applied by a fluid at equilibrium at a given Reservoir Engineering I, Jan. Sem. 2025 point within the fluid, due to the force of gravity. Increases in proportion to depth measured from the surface – due to the increasing weight of fluid. Value depends on the density of fluid. Path of well Water salinity: 0.433 psi/ft for fresh water. 0.45 psi/ft for saline water 55,000 ppm. 0.465 psi for 88,000 ppm. 11 11 Fluid Pressure Regimes Reservoir Engineering I, Jan. Sem. 2025 OP = FP + GP  At a given depth, the overburden pressure can be equated to the sum of the fluid pressure (FP) and the grain or matrix pressure (GP) acting between the individual rock particle.  Since the overburden pressure remains constant at any particular depth, then a reduction in fluid pressure will lead to a corresponding increase in the grain pressure, and vice versa. 12 12 6  Fluid Pressure Regimes The fluid pressure in hydrocarbon column are dictated by the dominant water pressure in the vicinity of the reservoir. Reservoir Engineering I, Jan. Sem. 2025 In a perfectly normal case, the fluid pressure at any depth can be estimated first by the water pressure connected to the reservoir. * Where, Pw = the pressure of the water at depth D. (dP/dD)w = the water pressure gradient, is dependent on the salinity, and for fresh water has the value of 0.4335 psi/ft.  Assumes: continuity of water pressure to the surface and the salinity does not vary with depth.  Equation is only applicable to normal hydrostatic pressure. 13 13 Fluid Pressure Regimes In the case of abnormal hydrostatic pressure, the water pressure at any depth can be calculated as: Reservoir Engineering I, Jan. Sem. 2025  dP   Pw    * D  14.7  C  dD  water  Where, C is a constant which is positive if the water is overpressured and negative if underpressured. 14 14 7  Fluid Pressure Regimes For the fluid in any sand to be abnormally pressured, the sand must be effectively sealed off from the surrounding strata so that hydrostatic Reservoir Engineering I, Jan. Sem. 2025 pressure continuity to the surface can not be established. Causes of abnormal pressure: Temperature change. Thermal effects. Geological changes. Osmosis between waters having different salinity. 15 15 Fluid Pressure Regimes Hydrocarbon pressure regimes: different in the densities of oil and gas are less than that Reservoir Engineering I, Jan. Sem. 2025 of water. the pressure gradients are smaller. 16 16 8  Fluid Pressure Regimes At the fluids’ contacts: the fluids in-contact have the same pressure. Reservoir Engineering I, Jan. Sem. 2025 𝑃 𝑃 𝑃 𝐷 𝐴 Where, A is constant. A can be estimated, if pressure of the oil at the given depth is known. Equating the equations above, the depth of oil-water contact can be estimated. 17 17 Fluid Pressure Regimes If the reservoir has oil, water and gas: two fluids Reservoir Engineering I, Jan. Sem. 2025 contacts, i.e. gas-oil contact (GOC) and oil-water contact (OWC). The pressure at the contacts 𝑷𝒐 𝑷𝒈 and 𝑷𝒘 𝑷𝒐. 18 18 9  Fluid Pressure Regimes Reservoir Engineering I, Jan. Sem. 2025 Pressure regimes in the oil and gas for a typical hydrocarbon accumulation. 19 19 Fluid Pressure Regimes  At the oil-water contact, at 5500 ft, the pressure in the oil and water must be equal otherwise a static interface would Reservoir Engineering I, Jan. Sem. 2025 not exist.  The pressure in the water can be determined using the following equation: Pw = 0.45 D + 15 (psia)  If we assume a normal hydrostatic pressure regime. Therefore, at the oil- water contact Po = Pw = 0.45 × 5500+14.7=2490 (psia)  The linear equation for the oil pressure, above the oil water contact, is then Po = 0.35D + constant  Since Po = 2490 psia at D = 5500 ft, the constant can be evaluated to give the Equation Po = 0.35D + 565 psia  At the gas-oil contact at 5200 ft, the pressure in both fluids must be equal and can be calculated by the above equ. to be 2385 psia. The equation of the gas pressure line can then be determined as  Po = 0.08D + 1969 psia 20 20 10  Fluid Pressure Regimes  Finally, using the latter equation, the gas pressure at the very top of the structure, Reservoir Engineering I, Jan. Sem. 2025 at 5000 ft, can be calculated as 2369 psia.  This figure shows that at the top of the structure, the gas pressure exceeds the normal hydrostatic pressure by104 psi.  Thus, in a well drilling through a sealing shale on the very crest of the structure there will be a sharp pressure kick from 2265 psi to 2369 psia on first penetrating the reservoir at 5000 ft.  The magnitude of the pressure discontinuity on drilling into a hydrocarbon reservoir depends on the vertical distance between the point of well penetration and the hydrocarbon water contact and, for a given value of this distance, will be much greater if the reservoir contains gas alone 21 21 Example  This figure illustrates another type of uncertainty associated with the determination of fluid contacts from pressure measurements. The reservoir has an exploration well that penetrate the gas cap.  A well test is conducted at a depth of 5100 ft from which it is determined that the Reservoir Engineering I, Jan. Sem. 2025 gas pressure is 2377 psia with gas gradient of 0.08 psi/ft.  The exploration well is penetrating the gas reservoir only and assume no oil in the well, estimate the gas pressure at the gas water contact at 5281 ft.  Assume the deepest point at which gas has been observed in the well is 5150 ft and the reservoir has an oil column, estimate the pressure at water oil contact and gas oil contact. 22 22 11  Example Assuming that the hydrocarbon reservoir has a normal hydrostatic pressure. An exploration well was drill and Reservoir Engineering I, Jan. Sem. 2025 hit the oil and gas zones. The gas oil contact is at 5500 ft. If the oil pressure at the depth 5500 ft is 2600 psia, estimate the oil water contact. Given = 0.34 psi/ft 23 23 Reservoir Temperature Earth temperature increases from surface to center. Reservoir Engineering I, Jan. Sem. 2025 Heat flow outwards generates a geothermal gradient. Reservoir geothermal gradients around 1.6oF/100 ft. Local and regional gradients are influenced by lithology. Local conditions, e.g. around the wellbore can be influenced by transient cooling or heating effects of injected fluids. Large thermal capacity and surface area of porous reservoir, flow processes in a reservoir occur at constant temperature. Obtained from wellbore temperature surveys. 24 24 12  Summary What have we learnt? Hydrocarbon Volumes Calculation Reservoir Engineering I, Jan. Sem. 2025 (Introduction) Fluid Pressure Regimes Reservoir Temperature 25 25 What are we going to learn next Reserve Estimation Reservoir Engineering I, Jan. Sem. 2025 Volumetric Calculation Recommended Text L.P. Dake; Fundamental of Reservoir Engineering Chapter 1: Some Basic Concepts in Reservoir Engineering 26 26 13  27 Open Reservoir Engineering I, Jan. Sem. 2025 27 14