Natural Gas Liquids - Paper Example

Natural gas: A natural mixture of gaseous hydrocarbons used for fuel and natural gas normally consists of methane, ethane, propane, butane and natural gasolines; natural gas can also be used as feedstock for the manufacture of ammonia/urea fertilizer; some components of natural gas can be extracted and used as feedstock for the petrochemical industry.

Natural gas liquids (NGL): Liquid hydrocarbon mixtures that are gaseous at reservoir

temperatures and pressures but are recoverable by condensation or absorption;

natural gasoline falls in this category.

Operating margin: The difference between the purchase and sales price of oil and gas; the

financial viability of petroleum companies is affected largely by the operating

margin set by the Government.

Step-out drilling: Drilling carried out adjacent to or near a proven area to ascertain the limits of

the reservoir.

Water injection: A secondary recovery method by which water is forced down a well, thereby

forcing crude oil to migrate toward adjacent oil wells to aid production.

Wellhead: Top of the production structure built over a gas wall.

Workover: Maintenance work carried out on a producing well to restore or increase production

of oil or gas.

Project Focus, Design and Rationale

An adequate supply of energy is critical for economic growth. To sustain economic growth at an acceptable level, the Government of UK has adopted a strategy that emphasizes efficient energy utilization while giving high priority to the development of indigenous .oil and gas resources. An important part of the Government's overall program for the oil and gas sector is to promote the development of known oil and gas resources to meet the country's growing need for commercial energy without an unsustainable increase in the country' a dependence on imported oil. The Government's efforts are directed toward increasing domestic oil production from the current 34 million tons of oil per annum (HMTPA) ((about 250 million barrels per annum (MMBPA)) to 48 HMTPA (about 350 HMBPA) and gas supply from the current 46 million cubic meters a day (HMCMD) to 60 HMCMD (about 140 MMBPA).

The proposed Project, the second to be assisted by the Bank in the oil and gas sector in UK, provides for the further development of the onshore X-field. Work under the Project is aimed at (i) development drilling of 216 oil, gas, and water and gas injection wells; (ii) workover of 125 wells; (iii) installation of the necessary surface facilities for oil and gas production; and (iv) construction of formation water treatment, water and gas injection, and utility and off site facilities. The Project is designed to produce 19.4 million tons of crude oil, 20.5 billion cubic meters of gas, 1.3 million tons of liquefied petroleum gas and 2.5 million tons of natural gas liquids (NGL) during its economic life. The output of the Project will replace imported oil and oil products, provide gas as fuel to power plants and industries, as feedstock for fertilizer production, provide NGL as feedstock for petrochemical production, and contribute towards the reduction of environmental pollution in the western region by lessening the use of coal and heavy oil products. The Project, through its economic life of 16 years, will enable the Government to achieve annual foreign exchange savings of about $148 billion a year.

Bank assistance for the Project is aimed at strengthening and extending policy reforms discussed with the Government in the context of the Bank-financed Special Assistance Project. The subject reforms are focused on encouraging greater private sector involvement in the energy sector, particularly the oil and gas sector. Bank assistance for the Project also aims at assisting the Oil and Natural Gas Commission (ONGC) to develop plans and take subsequent action for commercialization and efficiency improvements aimed at improving further its operational efficiency and at facilitating increased private sector involvement in its activities. This will help contribute toward its current effort in examining suitable modalities for developing its existing fields under joint ventures. In addition, one of the two accompanying technical assistance (TA) grants to be provided will help the Government to improve its future exploration offerings to attract increased private sector involvement in oil and gas exploration and development in UK.

The Project could face market, technical, safety and implementation delay risks. While there are ready markets for the oil and oil products produced by the Project, the gas market may not develop as forecast if there are delays in the establishment of gas-user facilities such as the power plants. In such an event, the gas supply to existing consumers could be increased to absorb part of the initial surplus. A delay in the commissioning of the two power plants will not significantly affect the economic viability of the Project. A Gas Linkage Committee has recently been set up by the Government to help coordinate development of the gas market and minimize the market risk for gas. Technical risks associated with inadequate oil and gas reserves and low productivity of oil and gas are considered small, as planned production is confined to an area whose reserves are proven and whose productivity has been sufficiently tested. The Project could suffer from fire hazards and well blowouts during drilling. To minimize such risks, all Project facilities will be designed and constructed in accordance with the industry's safety standards, and staff of the Executing Agency will be trained to operate and maintain the facilities safely. Delays in Project implementation could occur, but this will be minimized by the monitoring of the Project by the Regional Director of the Western Region and by the Production Monitoring team of the Executive Committee headed by the Chairman of ONGC. In addition, Bank staff will intensively supervise and monitor the progress of project implementation.

Structural Map of the X-Field

IntroductionThis field development programme describes the proposed development of the X-field by Xenon, a public limited company. The X-field is located approximately 210km East North East of mainland Britain in the Central North Sea in block UKCS 22/12. There are numerous neighbouring fields located close to the X-field, as can be seen in figure 1. Nearby existing developments include Nelson, 10km to North North West, and Forties, 40km North West. Other existing facilities include the Forties pipeline system, the Fulmar gas pipeline and the central area transmission system. The X-field lies in 81m of water.

1.2HistorySix appraisal wells penetrated the oil bearing Jurassic reservoir from 10126ft to 11175ft two years ago (see figure 2). Wells X-1 and X-2 are vertical and wells X-3 to X-6 are deviated by up to 25 degrees. All six were subsequently abandoned. From this appraisal phase various sources of information were collected. Mud logs were recorded during the drilling of each well. Four wells tests were carried out and eight uncontaminated fluid samples collected. Each well was petrophysically logged. A 2-dimensional seismic cross section of the reservoir was also taken. 1.31.3 Seismic Information

The available seismic is 2D and was shot in an NNW to SSE direction (see figure 3 and 4). The seismic is of moderate quality.

1.4 Petro physical Data

1.4.1 Wireline Logs

Petro physical logs which were run on all of the wells in the X-field. A full list of the logs that were run can be found in Table 1. The mud type in all the wells (with the exception of well 6 that is OBM) is a potassium system WBM.

1.4.2 Core

Core porosity, permeability and capillary pressure measurements are available for wells X1, X4 and X5. Examination of core samples indicated that the reservoir sand is relatively well consolidated. A small interval was identified as being slightly more friable. Sonic travel time also indicated that the reservoir sand is friable to moderately hard.

1.5Reservoir Fluids

PVT Analysis

Fluid samples from a total of eight depth intervals in exploration wells X-1 and X-2 were considered uncontaminated (or present in sufficient quantity) and therefore suitable for analysis. Two down hole samples from well X-1 were collected, but only one, at 10362 ft (TVDSS) was analysed because the oil content of the other sample was found to be far from sufficient to complete an analysis. Eight valid samples were collected from both the wellhead and separator during the drill stem testing of wells X-2, X-3, X-5 and X-6. A second PVT analysis was performed on surface samples collected from well X-3 and the results were compared with those obtained from the down hole samples. The results of these PVT analyses are presented in table 2.

Changing the separator pressures and temperature results in a different formation volume factor being obtained in both PVT reports from wells X-1 and X-2 (see appendix D, figures D.1, D.2, D.3, D.4). A normalisation process was performed in order to obtain an acceptable average oil formation volume factor for both wells and to use across the entire reservoir (see appendix D) [4]. The average formation volume factors obtained from both wells X-1 and X-2 are similar and are presented in figures 2 and table 3. The average reservoir fluid composition is shown below in table 4. From production technology optimisation it is known that a two stage separation process will be required in the field. First stage separation pressure is to be 300 psi, 200oF and the second stage with pressure at 30 psi, 80oF. From the Drill stem test performed in the 100% water bearing sand, a formation water sample was obtained and submitted to the laboratory for testing. The results are presented in tables five and six.

1.6 Reservoir Pressure

Repeat Formation Tester

RFT tests have been conducted for three well; X1, X2, and X5 to find the original reservoir pressure and oil water contacts. The measured pressure (Psi) at different depths (TVSS in feet) and the observed oil water contacts are summarised in table 7.

1.7 Well performance

Drill stem testing

Drill Stem Tests were carried out on wells X-2, X-3, X-5 and X-6. No tests were conducted on wells X-1 and X-4. A software package, entitled Pansystem, was used to analyse the well test responses. Input parameter data, including formation volume factor, total system compressibility for example were calculated from the PVT analyses (see section 2.4) and parameters such as porosity, water saturation, layer thickness and so on were obtained from the petrophysical analysis (see section 2.3). An injectivity test was also carried out in the aquifer. However, the results indicate that permeability is low and that the aquifer sand is...