N. BanerjeeOil India Ltd. Duliajan, India
The development of a new oil or gas field involves construction of various downstream facilities such as field flow lines, trunk lines, oil and gas collecting and processing stations, and transportation to refineries and consuming centers.
It is essential that these facilities be built on a schedule that allows the products to be transported and processed as early as possible.
Unless such an approach is initiated, the wells producing crude oil or natural gas will need to be shut-in in the absence of the other relative facilities. For quick returns on the investments, a realistic program and careful evaluation of the schedule is needed to ensure that early commissioning of the fields is possible.
One such program was evaluated by Oil India Ltd. for developing a nonassociated gas field.
THE PROJECT
Oil India Ltd. is an oil company that has been operating in India for over 100 years. Its major oil and gas fields are in the state of Assam in northeast India.
Per year, the company produces about 3 million tons of crude (60,000 bo/d) and 1.6 billion cu m (155 MMcfd) of associated natural gas from these fields.
Oil India's primary business is exploration, drilling, and production of crude oil. In the course of developing oil fields, several large reservoirs of free natural gas have been discovered. Because the demand for the gas has not been high, there has been no concerted effort to develop these free gas fields.
The limited local demand, mainly from a fertilizer plant, petrochemical plant, some tea gardens, and small-scale industries nearby, has been met with associated gas produced from crude oil.
But with plans for large-scale industrialization of the area, especially a gas-based power plant and a gas cracker plant for downstream petrochemical units scheduled for the near future, the existing supply of gas will be inadequate. Therefore, early development of a major nonassociated gas field will be needed.
The planned development project is for nonassociated gas fields discovered in the early 1970s.
The cost of the project, in late 1991, was estimated to be $160 million. This cost includes about 60% Indian currency and the balance in foreign currency.
The project is awaiting government clearance that has been delayed because of two downstream projects. These projects are a 120 mw gas-based power plant and a gas cracker plant within a petrochemical complex that will use this gas as feedstock.
Fig. 1 shows the typical gas balance diagram with existing associated gas, supplemented with some nonassociated gas, and the major nonassociated gas, planned to be produced under this project.
The project is aimed at developing five free gas fields situated close by and not far from the field headquarters of the company. The key plan of the proposed development is shown in Fig. 2.
The major components of the project are:
- Drilling 30 development wells to depths varying between 2,800 and 3,000 m (9,186-9,842 ft) within the areas delineated by earlier exploratory drillings.
- Construction of five field gathering and treatment stations (FGSs) and connecting them to a central gathering station (CGS) near the field headquarters.
- Laying of about 90 km (56 miles) of field flow lines and 60 km (37 miles) of trunk pipeline.
- Other associated infrastructures along with environmental control measures.
The estimated gas reserve is about 950 bcf in aggregate and with a recovery factor of 70%, the recoverable reserve works out to about 670 bcf.
From production test data, plans are to produce at the rate of 100 MMcfd, thereby sustaining the production level for an 18-year plateau period. In addition, possible reserves of another 640 bcf may exist in nearby fields in which further exploration will be necessary. If these reserves are established, the plateau period will be further extended.
Out of five fields producing the gas, three are wet gas in which the natural gas liquid (NGL) percentage is more than 5%. The other two fields produce dry gas with NGL less than 5%.
The produced volume will be about 60 MMcfd wet gas and 40 MMcfd dry gas. Thus, there will be two gas streams. Three field gathering stations will be equipped with liquid separation facilities and two FGSs will handle dry gas.
The central gathering station will also have liquid separation facilities. The schematic of the wet and dry gas handling systems is shown in Fig. 2.
The project, now with the government and environmental authorities for final clearance, is planned to be completed in 3 years from approval. Meanwhile, a detailed program of action and evaluation of the program has been carried out.
The following analysis shows how the program has been evaluated to eliminate any imbalance during project execution and to ensure that the financial viability is not unduly affected.
PROGRAM ASSUMPTIONS
To work out an economical program and to evaluate it, the following norms have been adopted. These are based on the past experience, as stated earlier.
- Drilling efficiency is an average 2.8 rig months for each well up to 3,000 m depth, from rig up in one well to rig up in the next well.
- for each field gathering station, construction takes 5 months for wet gas handling facilities and 3 months for dry gas.
- Central gathering stations take 6 months for construction.
- Design, engineering, and tendering for all gathering stations take 6 months.
- Laying of field flow lines and trunk pipelines averages 1 km/day plus 4 months for tendering and awarding the contracts.
The actual time for implementing the project will be 33 months, leaving 3 months for final linkup and integrated testing of the entire system.
Market demand for the nonassociated gas is estimated to be:
- Month 9 to 15 3.8 MMscfd
- Month 15 to 24 6 MMscfd
- Month 24 to 36 94 MMscfd
- Beyond month 36 for 18 years = 100 MMscfd (plateau).
Average productivity of each well has been assumed as 3.33 MMscfd for 30 wells to produce 100 MMscfd. The supply to the consumers can start from the 12th month after completion of the CGS.
THREE-RIG PROGRAM
The schedule for three rigs is shown in Fig. 3. Under this program, three rigs have been planned to be deployed, each drilling 10 wells in 28 months. The project can be completed in less than the planned 36 months, a distinct advantage.
This program can be evaluated from the relationship of consumer demand of gas and its availability (Table 1).
Because, for the three-rig case, both shortfall and surplus will be less until the gas storage project is implemented, the total loss is 12,480 MMscfd. At a price of $1.40/Mscf this equals $17.47 million, or 10.92% of the project cost of $160 million.
FOUR-RIG PROGRAM
Fig. 4 shows the schedule for four rigs. Initially, four rigs are planned to be deployed. Towards the end, between months 30 and 33, Rigs 1 and 2 can be redeployed to complete the remaining four wells.
The relationship between demand and supply of gas, as analyzed from the diagram, is also shown in Table 1.
In this case, total loss is only 4,980 MMscf. This equals $6.97 million or 4.36% of the project cost.
Thus, it is evident that the four-rig program is more desirable. It may be possible to work out more economical programs, but certain practical difficulties should be kept in mind. These are:
- Number of rigs to be deployed should be optimum.
- Splitting the construction activities among too many contractors will pose problems in coordination and may not be attractive to many good contractors.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
