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This paper discusses about the oil losses due to emulsion, flash, and mixing oil phenomena that frequently happened in the oil and gas companies. The goals of this work are to calculate the emulsion and vapor correction volumes, shrinkage correction volume of the mixture of two or more crude oils with different densities, and to compare between the common proportional method that usually utilized in petroleum industries and the new proposed stratified method for determining of sharing oil losses. The mixing of crude oils from 7 shippers in Krisna field would be used as a case study, and the equation of API 12.3 was chosen to calculate a shrinkage correction volume. Oils from shippers S1, S2, and S3 were first mixed together in TANK-1 of the 1st station; the mixed oil of TANK-1 was then transported to the next station and stored in the TANK-2 and mixed with other oils from shippers S4 and S5; and finally, the mixed oil of TANK-2 was transported to the final station and stored in the TANK-3 and mixed with other oils from shippers S6 and S7. The proportional method gave almost the same shrinkage correction factor (SCF) for all shippers about 0.20%, while stratified method resulted SCF in between 0.05 and 0.31%. Based on our analysis, more often oil mixes with others its volume would be more decreased. The stratified method is therefore recommended to determine sharing oil losses since it gives a fair result.

CO2 gas injection is one of the recommended enhanced oil recovery (EOR) methods by injecting CO2 through reservoir pores after the residual saturation is reached, since CO2 dissolves easily in oil phase as confirmed by many other researchers in pertaining field studies. An integrated system is urgently required for assessing CO2-EOR study, covering multi-disciplinary aspects as follows: geology, geophysics, reservoir, production, process and economic. Hence, those systems must be reliable in suggesting final decision for feasibility of CO2-EOR operation program, applicable either for pilot scale or for full scale. This paper is proposing an integrated system evaluation, which has the following features: (1) estimate fraction of dissolved CO2, (2) estimate viscosity reduction, (3) estimate future oil productivity index resulted, (4) forecast incremental oil production, (5) estimate surface facilities equipment design, (6) evaluate economical aspects and (7) generate final decision for feasibility of CO2-EOR operation program. Finally, as the main objective of this program, those systems will present a picture of essential reason why we need to promote or reject CO2-EOR plan program, and also some recommendations will be presented in case the CO2-EOR plan does not perform as expected.

Carbon dioxide (CO2) gas could increase oil recovery by means of swelling, evaporating and lowering oil viscosity. In the displacement front, injected gas may become enriched by the oil components and gas may dissolve into the reservoir oil. By assuming that local thermodynamic equilibrium is occurring at the oil-gas interface, the phase behavior can be calculated by the equation of state. The displacement process can be modeled by a set of differential equations, called the mass balance equations, which can be written for each component in the reservoir oil and the CO2 gas injected. The linear velocity component in the mass balance equation is expressed by Darcy's law for oil and gas phase flow, which comprise oil and gas permeability, oil and gas viscosity and pressure gradient terms. A set of the flow equation then solved numerically by the use of a one dimensional compositional simulator. The simulator has been validated by analytical methods, which is based on the method of characteristics. In this study, we want to see the potential of CO2 injection application in improving oil recovery by simulating a slim tube experiments. CO2 gas is available in large quantity in the Natuna Sea and some place in Kalimantan, Indonesia. The benefit of the study is that we could predict the recovery efficiency of CO2 gas injection in the field by combining the results here with the macroscopic areal sweep and invasion efficiencies obtained from other models or simulations. And, the potential application of the study is that we could have a good estimate of the recovery improvement under CO2 gas injection, which will be the basic input parameters for the economic feasibility study and also a decision can then be made whether to implement or abandon the prospective project. Introduction Carbon dioxide gas as an injection fluid into oil reservoirs has been a recognized well and tested as Enhanced Oil Recovery (EOR) method, because CO2 dissolves easily into oil, it reduces oil viscosity, and it can extract the light components in oil at sufficiently high pressure, and it can become miscible with oil at very low pressure. However, before a further decision be made on whether to apply it in field or not, generally some laboratory experiments need to be done, one of them being a series of slim tube experiments. The experiments on slim tube will indicate the microscopic efficiency of the injection process. They need to be combined with the macroscopic sweep efficiency and invasion efficiency obtained from the reservoir characterization, to have an overall injection efficiency of the process. Since experiments on slim tube at high pressures are costly, time consuming and prone to experimental failures, it is of great interest to simulate those experiments with a numerical simulator. With a numerical simulator, besides the economic and time benefits, we could also calculate results on certain conditions, which otherwise would have never been possible with experiments due to technical constraints. The injection pressures and temperatures applications of CO2 injection could vary from low, intermediate up to high. The phase behavior of oil and CO2 gas and the transfer of components between oil and gas, based on the assumption that thermodynamic equilibrium always occur at the oil-gas front, can be described with adequate accuracy by equations-of-states for real gases, which were introduced by van der Waals. CO2 gas in large amount has been discovered in theXC-08 reservoir, Natuna Sea, Indonesia, co-existing with commercial methane gas. Since CO2 gas is an unfriendly substance from environmental perspective, the problem arised as how to separate, remove the CO2 gas from the methane, and to dispose it at a safe place somewhere. It is more interesting economically, however, to make use of the produced CO2 as far as possible. One of the alternatives is to use the produced CO2 gas as an injection fluid in the nearby fields. Many injection schemes using CO2 have been applied for the oil wells, including CO2 gas continuous injection, CO2 gas slug followed by water, CO2 gas or liquid slug followed by alternate water and CO2 gas injection (WAG), CO2 - surfactant foam slug followed by water injection and carbonated water injection.

The use of fractal model in Pressure Transient Test Analysis was introduced by Chang and Yortsos in 1990. Their concept was derived from the assumption of Warren and Root model where their reservoir contains two systems with contrast in porosity and pemeability properties, which are well-known as matrix and fracture network. The fracture network is assumed to be connected and distributed as fractal object in a homogeneous medium (matrices) of Euclidean Geometry. Fluid flow from reservoir to well occurs only through the perfectly connected fracture network. Based on these assumptions, Chang and Yortsos developed the unsteady-state flow of slightly compressible fluid and proposed an extension of the diffusivity equation to model transient flow in fractured reservoirs, especially in single well testing. The physical and mathematical model descriptions are developed from Chang and Yortsos model. By Type Curve Matching technique, we can analyze the interference test in reservoir considered as a complex naturally fractured reservoir such as the one operated by Amoseas Indonesia Inc. Besides transmissibility and storativity we can also obtain the fractal dimension which can be used to predict the complexity of the reservoir. Introduction In 1982, Mandelbrot B.B., introduced the concept of fractal geometry that is a relatively new approach for describing and modeling of complex objects and processes. In Petroleum Engineering these concepts are then used for characterizing fractal behavior of porous media and analyzing pressure gradient of fractal objects. Fractal geometry provides a method to account for a great variety of such transients under the assumption that the network behaves as fractal objects. The application of fractal model or concepts to pressure transient testing in fractal fractured system was proposed by Chang and Yortsos, who described the diffusivity equation to transient flow model in fractal reservoir for single well problems. The fractal model is able to appropriately describe a complex naturally fractured reservoir which has a large number of different scale, poor fracture connectivity and disorderly spatial distribution. In the pressure transient case, the application of fractal model has been examined by Acuna et. al., (Ref. 2), for analyzing single well test data in naturally fractured reservoirs. Using their model, a method that could be used in an interference test analysis was developed. By considering at least two interfering wells in a fractal reservoir, one of them being an active well and the others are observation wells, a pressure transient equation was formulated by Abdassah, D., and Aprilian, S. (Ref. 8). In this paper, development and practical application of new type curves using fractal concept for handling the multiple well test problems, especially in analyzing the interference test, are discussed. The objective of this study is to obtain reservoir characteristics such as permeability thickness, storativity, transmissibility and fractal dimension of the Darajat Field, Amoseas Indonesia, Inc., (Fig. 1), by applying the new type curve in interference test.