VALIDATION OF PVT PARAMETERS IN SATURATED BLACK OIL RESERVOIR USING STANDING CORRELATIONS 1 Ehirim O. Emmanuel and 2 Ngutsav Sesugh Caleb ABSTRACT Pressure-Volume-Temperature (PVT) analysis of reservoir fluid is an important concept that provides some useful information on the properties of a reservoir with hydrocarbon in place. There is therefore the need to validate and where necessary correct PVT data at the minimal cost before application. This work was able to evaluate the PVT parameters of a saturated black oil reservoir in the Niger Delta area of Nigeria, validates and corrects the data due to error from sampling stage using analytical method. The basic mathematical tools used in this work are standing correlations which are standard correlations in PVT analysis with satisfactory level of accuracy. INTRODUCTION The volumetric behaviour of reservoir fluid due to changes in temperature and pressure is influenced by the physical properties of the fluid such as composition,density,viscosity, etc. This behavior is easily understood through analysis of results obtained from either controlled PVT (Pressure-Volume-Temperature) experiments on crude oil samples, or field test (or induction data). Observation has shown that PVT parameters measured from bottom-hole samples taken from saturated reservoir do not always represent the true condition in the reservoir due to the effects of excessive drawdown pressure (that is , the difference between the bottom-hole flowing pressure and the initial reservoir pressure),gas saturation, e.t.c (Dake 1978). It is therefore becoming a normal practice for PVT data on saturated black oil reservoir to be evaluated before use. The evaluation procedure involves using the gas-oil contact (GOC) to estimate the bubble-point pressure of the oil; where the data is found to be wrong due to the drawdown pressure ,the PVT parameters have to be re-determined starting from the sampling stage to the data –report stage or validated and corrected using standard correlations. There are five types of reservoir fluids: Black oil, volatile oil, retrograde gas, wet gas and dry gas. It is important that the field engineer determines the type of fluid in the early life of a reservoir so as to enable him or her decide the method of sampling, the type and size of surface equipment to be used, the causational procedures for determining oil and gas in a place, the techniques of predicting oil and gas reserves, the plan of depletion, and selection of enhanced recovery method. Three properties that are readily available as rules of thumb for identifying each of the five types of reservoir fluids are the initial producing gas-oil ratio, API gravity of the stock-tank liquid, and the colour of the stock-tank liquid, but the initial producing gas-oil ratio is by far the most important indicator of the type of fluid (Mc Cain, 1990). Note that stock-tank-oil means dead oil (i.e oil with zero gas at atmospheric pressure) corrected to 60 ℉. The name black-oil is misnomer since the colour of this type of oil is not always black. This type of reservoir fluid has also been called low-shrinkage crude oil or ordinary oil (Mc Cain, 1990). Black oils consist of a wide variety of chemical species including large, heavy, non-volatile molecules. The phase diagram predictably covers a wide temperature range. Black oils exhibit initial producing gas-oil ratios of above 2000scf/stb (standard cubic feet per stock-tank barrel) or less. Producing gas-oil ratio will increase during production. When reservoir pressure falls below the bubble-point pressure of the oil, the stock-tank oil usually will have gravity below 45 ° API which decreases slightly with time until late in the life of the reservoir when it will increase (Mc Cain, 1990). The stock-tank oil is very dark, often black, indicating the presence of heavy hydrocarbons, sometimes with a green or brown cast. Laboratory analysis will indicate an initial oil formation-volume factor of 2.0 reservoir barrels per stock-tank barrels (res bbl/ stb) or less. Reservoir engineering requires knowledge of how much gas is in the oil at the reservoir conditions, and how much of the oil would shrink if it were brought to the surface. The three basic PVT properties used to serve this purpose are solution gas-oil ratio, oil formation-volume factor and gas formation-volume factor; other PVT