D. Mangalsingh, and T. Jagai, SPE Abstract The CO2 immiscible process is a potentially viable method of EOR for local reservoirs. Although this type of flood is being conducted on a pilot scale in Trinidad, no laboratory work has been done to support this field effort. This paper presents the results of the first laboratory investigation of CO2 immiscible displacement of local crudes using both the continuous injection method and the water alternating gas method (WAG). Introduction The continuous depletion of Trinidad's oil reserves necessitates the development and improvement of thermal and non thermal enhanced recovery techniques. Approximately 60% of the present oil reserves cannot be exploited because of present technical and economic constraints. The use of steam as a recovery agent loses it's economic viability when the reservoir is deeper than 1000m and when the formation is less than 10m thick. This is as a result of the heat loss associated with such conditions. The problem of poor areal and vertical sweep efficiency has limited the recovery in many heavy oil reservoirs. During the period 1920-1930 papers and patents were published indicating that carbon dioxide was a fluid capable of recovering oil from hydrocarbon reservoirs. In 1945 Poettman and Katz discussed the phase behaviour of CO2 and paraffin systems. Their studies indicated that a 10% to 20% increase in oil volume and a viscosity reduction too less than 0.1 of the original value was due to the solubility of the CO2 in the paraffin. The 1950's and 1960's saw emphasis in the application of CO2 as a miscible displacing fluid. At that time researchers understood the limitations of miscible CO2 flooding to be:High pressures that were required to achieve miscibility;Reservoir depths greater than 1000m;Crude oils of 30 API gravity and over gave high miscible pressures. These restrictions prompted researchers to investigate the effectiveness of CO2 immiscible displacement for oil recovery. Four U.S. patents were issued to Martin et al, in 1959 relating to immiscible use of CO2 for oil recovery. The early 1970's saw field applications of immiscible CO2 which showed potential performance. The methods of CO2 injection were mainly continuous and huff and puff until the identification of WAG in the 1980's. Continuous CO2 was deficient in areal sweep efficiency which resulted in early carbon dioxide breakthrough. Research also indicated that the production gas oil ratio (GOR) for continuous injection was very high. WAG injection resulted in lower mobility of carbon dioxide, thereby increasing sweep efficiency and lowering produced GOR. Rojas and Farouq Ali performed a scaled model study of carbon dioxide/brine injection strategies for heavy oil recovery from thin formations and disclosed the potential of WAG application. CO2 immiscible displacement is a well established technique for increasing the recovery of crudes. This has been applied to reservoirs throughout the world. CO2 injection into Trinidad reservoirs started a few decades ago. Recovery as a result of this effort has been insignificant. Within the last few years, a more determined effort to implement CO2 immiscible displacement on a pilot scale has been attempted. However, no laboratory work has been conducted to support this field effort. This paper describes the laboratory work that is being conducted to investigate the behaviour of local crudes when subjected to immiscible displacement by CO2 flooding. It presents the findings to date and compares them with those published. It also attempts to identify the important parameters that enhance recovery and seeks to optimize these parameters. The effect of continuous injection of CO2 on recovery has been studied. This has been compared to the recovery due to injecting alternate slugs of CO2 and water. Recovery Mechanism Immiscible CO2 flooding is a technique in which the flow properties of the oil in the reservoir are improved. The concept of immiscible CO2 flooding implies that CO2 is injected at subcritical pressures. In addition to providing energy to the reservoir, four mechanisms which contribute to increased oil recovery have been documented. P. 591
The petroleum sector of the Republic of Trinidad and Tobago has made substantial contribution to its economy over the last 90 years. The major contribution during the period 1908 to 1995, came from oil production. Starting in 1996, there were major developments in the gas sector to the extent that revenues from gas production in 2000, exceed that from oil production. This paper reviews the natural gas industry and summarises the factors that contributed to the successful monetization of stranded gas reserves. The Government of the Republic of Trinidad and Tobago (GORTT) have undertaken many initiatives that have promoted upstream exploration and production activities both onshore and offshore. As a result, a number of investors were encouraged to explore for and develop gas reserves resulting in the proved gas reserves increasing to 22 Tcf in 2000. Policies were also adopted which facilitated the development of a range of petrochemical and other gas based industries. These encouraged investments in the methanol, fertilizer, iron and steel industries. More significantly, Train 1 of a liquefied natural gas plant was commissioned in 1999, and the first shipment was exported in April 1999. This plant is being expanded, with the construction of Trains 2 and 3 presently in progress. Consideration is being given to Trains 4 and 5. The coming onstream of Trains 2 and 3, together with an additional ammonia plant and a methanol plant, will reduce the reserves to production ratio from 37 years at January 2000 to 21 years by December 2003, until more reserves are proved. Future potential projects aimed at sustaining the development in this sector have also been identified. In this regard, additional deep-water acreage will be placed up for bids, and discussions are ongoing for the establishment of an aluminium smelter plant, additional fertilizer plants, an ethylene project and a gas to liquids project. Introduction Natural gas is the fastest growing energy source worldwide1. The growth in demand for natural gas as a fuel has been encouraged by the global concerns for the environment. When it is burned, natural gas releases less CO2, less sulfur dioxide, and less particulate matter to the atmosphere, per unit of energy than liquid hydrocarbons or coal. Trinidad and Tobago's proven natural gas reserves have grown significantly over the last twenty five years, from 4 Tcf in 1975 to 22 Tcf in 2000. Trinidad and Tobago is located at the southern end of the Caribbean archipelagic chain. The twin island state consists of a land mass of 5,131 sq. km (Fig. 1), has a population of 1.3 million, and geologically, it forms part of the South American mainland. Trinidad's location is favourable as it is only 7 miles from South America, 2100 miles to North America, and 4000 miles to Europe. In Trinidad, oil and gas are found in the south of the island, and offshore on the southeast and southwest coasts. Non-associated natural gas is found off the north and southeast coasts2,3,4. The first oil well was drilled in 1866 in South Trinidad. In 1908, commercial oil production began, and for the period 1908 to the late 1960's, crude oil production was the focus of attention. Following a peak production level of 214,000 bopd in 1978, crude oil production level steadily declined to 124,000 bopd in 1999 (Figs 2 & 3). On the other hand, the first commercial use of natural gas was in 1953 as a fuel for power generation. In 1959, natural gas was used for the first by time by Federation Chemical Ltd. to manufacture anhydrous ammonia3,4.
Graphical application of the gas Material Balance Equation (MBE), P/Z plots, have typically been used to predict the gas in place (GIP) of volumetric reservoirs. Few reservoirs however, are truly volumetric and several workers have developed procedures to correct such P/Z plots, particularly in over pressured regimes, for the pressure maintaining effects of rock collapse and/or shale water influx. The paper examines and discusses the applicability of eight (8) such procedures to the mildly overpressured, relatively low yield, gas condensate Kiskadee Field in which the original GIP is known from late life P/Z data and in which pressure maintaining effects on the early life P/Z data were not previously recognised. Production, bottom hole pressure, PVT and pore volume compressibility data are used to analyse the early and late life P/Z data of each identified fault block and to determine the extent and causes of apparent early life pressure maintenance as well as observed variations in the degree of pressure maintenance in individual blocks. A modification is proposed to the Bourgoyne procedure that accurately corrects the early life P/Z data of mildly overpressured reservoirs. A further modification is proposed to correct late life P/Z data for the effects of decreasing shale water influx and increasing water saturation. This further modification is successfully applied and results in GIP estimates that are within 3 % of the known volume. Introduction An estimate of the Original Gas In Place (OGIP or Gi) for a volumetric gas reservoir can be obtained from volumetric gas material balance considerations and yields:P/Z=Pi/Zi-(P i/ZiGi)Gp . . . (1) This linear relationship is the expression of a constant volume reservoir and assumes that rock and water expansion are negligible and that there is no net movement of gas into or out of the reservoir volume of interest. A material balance plot of P/Z vs. Gp for a volumetric, depletion drive gas reservoir generates a straight line of slope -(Pi / ZiG i) with an intercept of Pi / Zi for Gp=0. Extrapolation of the straight line to the Gp axis i.e. P/Z=0, yields the OGIP. Many gas or low yield gas condensate reservoirs do not yield linear plots but instead may curve upwards or downwards2. The constant volume assumption is then not valid. In addition to bad data, an upwards or downwards curving P/Z plot may be due to a number of reasons inclusive of water influx, drainage/leakage into the reservoir, subsidence/compaction drive, expanding oil rim (upwards curving) or retrograde condensation, drainage/leakage out of the reservoir, competitor overproduction and/or overpressured reservoir (downwards curving). Retrograde condensation is usually not significant enough to result in downwards curvature13. Downward curving plots usually plot more accurately as a continuous curve but are generally approximated by two (2) linear segments with distinct slopes that yield a good fit to the end points of the data set with a poor match in the area of intersection9. The slope of the early life data (the first slope) extrapolates to an Apparent Gas In Place (AGIP). The late life data plots with a higher slope and extrapolates to the OGIP. Dependent on the severity of the downward curvature, extrapolation of early life data may yield grossly inflated estimates of the GIP with consequent deleterious effects on the ability of the Operator to efficiently manage and produce the field. This is particularly important where long-term contractual arrangements are in force for the supply of gas from the field as pertains for the majority of Trinidad's East Coast gas reservoirs. Kiskadee Field The Kiskadee Field is located 40 kilometres off the eastern coast of Trinidad in approximately 270' of water. The field was discovered in 1977 with the drilling of two (2) exploration wells that tested gas-condensate from the primary reservoir sands at 15,500' subsea (Kiskadee Sand). The sands are mildly overpressure (0.55 psi/ft), Pliocene age, shallow marine, deltaic deposits with an average porosity of 25% and permeabilities within the cleaner sands of between 50 to 100 mD. The field lies along the gently dipping, northwest plunging structural nose of a major (Cassia) anticlinal structure. Primary structural elements are northwest trending normal synthetic faults, downthrown to the northeast, that divide the field into four (4) productive fault blocks (FBs) that are as shown in Figure 1.
The Gulf of Paria (GOP) is a semi-enclosed basin that provides access for all sea-going traffic to the four major ports on the west coast of Trinidad. This traffic includes tourist cruise liners, powerboats and yachts for recreation; cargo ships for transporting methanol, ammonia, and urea; tankers carrying crude oil and refined products to and from the refinery; and large, liquefied natural gas tankers. The GOP is considered a high-risk area for marine accidents and related spills because of this voluminous oceanic traffic. It also supports a range of fragile ecosystems including several beaches and the Caroni swamp, all of which can be adversely affected by any kind of discharge into this area. Petroleum Company of Trinidad and Tobago Limited (PETROTRIN), in discharging its responsibility, has put in place many systems to mitigate the damage resulting from such a situation should it occur. The most recent has been the acquisition of a commercially available software package that can be used to predict the movement of oil spills during an actual incident. Wind speed and direction, and mean tidal and background currents for the GOP were used to customize the model for the marine area bounded by the points 10.0234°N 62.2059°W, 10.0234°N 61.4911°W, 10.06796°N 61.4911 °W, and 10.06796 °N 62.2059 °W. The movements of surface drifters launched from a boat were recorded with time using a handheld global positioning system (GPS). Model simulations were generated and compared with field data to determine the model's capabilities and limitations for predicting the spill movement in the GOP. The trajectories predicted by the model were consistent with the actual movement of the surface drifters. Continuous updates of the movement of an actual spill will allow improved predictions and thereby assist response teams in determining and prioritizing the next course of action.
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