Field life

Introduction and Commercial Application This section provides an overview of the activities carried out at the various stages of field development. Each activity is driven by a business need related to that particular phase. The later sections of this manual will focus in some more detail on individual elements of the field life cycle. 

Maintenance and operating costs represent the major expenditure late in field life. These costs will be closely related to the number of staff required to run a facility and the amount of hardware they operate to keep production going. The specifications for product quality and plant up-time can also have a significant impact on running costs. 

It is expected that seismic iwill become even more important in determining field development strategies throughout the total field life. Indeed, many mature fields have several vintages of seismic, both 2D and 3D. 

Introduction and commercial application Safety and the environment have become important elements of all parts of the field life cycle, and involve all of the technical and support functions in an oil company. The Piper Alpha disaster in the North Sea in 1988 has resulted in a major change in the approach to management of safety of world-wide oil and gas exploration and production activities. Companies recognise that good safety and environmental management make economic sense and are essential to guaranteeing long term presence in the industry. 

In addition, the separator temperature and pressure of the surface facilities are typically outside the two-phase envelope, so that no liquids form during separation. This makes the prediction of the produced fluids during development very simple, and gas sales contracts can be agreed with the confidence that the fluid composition will remain constant during field life in the case of a dry gas. 

Reservoir fluid sampling is usually done early in the field life in order to use the results in the evaluation of the field and in the process facilities design. Once the field has been produced and the reservoir pressure changes, the fluid properties will change as described in the previous section. Early sampling is therefore an opportunity to collect unaltered fluid samples. 

Data gathering in the water column should not be overlooked at the appraisal stage of the field life. Assessing the size and flow properties of the aquifer are essential in predicting the pressure support which may be provided. Sampling of the formation water is necessary to assess the salinity of the water for use in the determination of hydrocarbon saturations. 

At each stage of a field life cycle raw data has to be converted into information, but for the information to have value it must influence decision making and profitability. 

Volumetric estimates are required at all stages of the field life cycle. In many instances a first estimate of how big an accumulation could be is requested. If only a back of the envelope estimate is needed or if the data available is very sparse a quick look estimation can be made using field wide averages. 

This section will consider the role of appraisal in the field life cycle, the main sources uncertainty in the description of the reservoir, and the appraisal techniques used to reduce this uncertainty. The value of the appraisal activity will be compared with its cost to determine whether such activity is justified. 

Appraisal activity, if performed, is the step in the field life cycle between the discovery of a hydrocarbon accumulation and its development. The role of appraisal is to provide cost-effective information with which the subsequent decision can be made. Cost effective means that the value of the decision with the appraisal information is greater than the value of the decision without the information. If the appraisal activity does not add more value than its cost, then it is not worth doing. This can be represented by a simple flow diagram, in which the cost of appraisal is A, the profit (net present value) of the development with the appraisal information is (D2-A), and the profit of the development without the appraisal information is D1. 

Seismic surveys are traditionally an exploration and appraisal tool. However, 3-D seismic is now being used more widely as a development tool, i.e. applied for assisting in selecting well locations, and even in identifying remaining oil in a mature field. This was discussed in Section 2.0. Seismic data acquired at the appraisal stage of the field life is therefore likely to find further use during the development period. 

Reservoir engineers describe the relationship between the volume of fluids produced, the compressibility of the fluids and the reservoir pressure using material balance techniques. This approach treats the reservoir system like a tank, filled with oil, water, gas, and reservoir rock in the appropriate volumes, but without regard to the distribution of the fluids (i.e. the detailed movement of fluids inside the system). Material balance uses the PVT properties of the fluids described in Section 5.2.6, and accounts for the variations of fluid properties with pressure. The technique is firstly useful in predicting how reservoir pressure will respond to production. Secondly, material balance can be used to reduce uncertainty in volumetries by measuring reservoir pressure and cumulative production during the producing phase of the field life. An example of the simplest material balance equation for an oil reservoir above the bubble point will be shown In the next section. 

The aquifer response (or impact of the water injection wells) may maintain the reservoir pressure close to the initial pressure, providing a long plateau period and slow decline of oil production. The producing GOR may remain approximately at the solution GOR if the reservoir pressure is maintained above the bubble point. The outstanding feature of the production profile is the large increase in water cut over the life of the field, which is usually the main reason for abandonment. Water cut may exceed 90% in the final part of the field life. As water cut increases, so oil production typically declines a constant gross liquids (oil plus water) production may be maintained. 

The amount of detail input, and the type of simulation model depend upon the issues to be investigated, and the amount of data available. At the exploration and appraisal stage it would be unusual to create a simulation model, since the lack of data make simpler methods cheaper and as reliable. Simulation models are typically constructed at the field development planning stage of a field life, and are continually updated and increased in detail as more information becomes available. 

The end of field life is often determined by the lowest reservoir pressure which can still overcome all the pressure drops described and provide production to the stock tank. As the reservoir pressure approaches this level, the abandonment conditions may be postponed by reducing some of the pressure drops, either by changing the choke and separator pressure drops as mentioned, or by introducing some form of artificial lift mechanism, as discussed in Section 9.7. 

Crude oil and gas from offshore platforms are evacuated by pipeline or alternatively, in the case of oil, by tanker. Pipeline transport is the most common means of evacuating hydrocarbons, particularly where large volumes are concerned. Although a pipeline may seem a fairly basic piece of equipment, failure to design a line for the appropriate capacity, or to withstand operating conditions over the field life time, can prove very costly in terms of deferred oil production. 

In the above example, where the ultimate recovery remains unchanged throughout the field life, the capital allowance rate remains a constant factor of 700/250 = 2.8/bbl. 

The project cashflow s constructed by performing the calculation for every year of the project life. Atypical project cashflow is shown in Figure 13.9, along with a cumulative cashflow showing how cumulative revenue is typically split between the capex, opex, the host government (through tax and royalty) and the investor (say the oil company). The cumulative amount of money accruing to the company at the endof the project is the cumulative cash surplus or field life net cash flow. 

The cumulative cash surplus accrues to the investor at the end of the economic lifetime of the project, and may be termed the field life net cashflow. 

Petroleum economics is used at exploration, appraisal and development stages of the field life, to help to make the following typical decisions ... 

Figure 14.5 Change of estimate of UR during the field life...

As introduced in Section 14.2, bottlenecks in the process facilities can occur at many stages in a producing field life cycle. A process facility bottleneck is caused when any piece of equipment becomes overloaded and restricts throughput. In the early years of a development, production will often be restricted by the capacity of the processing facility to treat hydrocarbons. If the reservoir is performing better than expected it may pay to increase plant capacity. If, however, it is just a temporary production peak such a modification may not be worthwhile. 

The types of facilities bottleneck which appear late in field life depend upon the reservoir, development scheme and facilities in place. Two of the most common capacity constraints affecting production include ... 

In high permeability reservoirs, wells may produce dry oil for a limited time following a shut-in period, during which gravity forces have segregated oil and water near the wellbore. In fields with more production potential than production capacity, wells can be alternately produced and shut in (intermittentproduction) to reduce the field water cut. This may still be an attractive option at reduced rates very late in field life, if redundant facilities can be decommissioned to reduce operating costs. 

As solution gas drive reservoirs lose pressure, produced GORs increase and larger volumes of gas require processing. Oil production can become constrained by gas handling capacity, for example by the limited compression facilities. It may be possible to install additional equipment, but the added operating cost towards the end of field life is often unattractive, and may ultimately contribute to increased abandonment costs. 

Introduction and Commercial Application Eventually every field development will reach the end of its economic lifetime. If options for extending the field life have been exhausted, then decommissioning will be necessary. Decommissioning is the process which the operator of an oil or natural gas installations will plan, gain approval and implement the removal, disposal or re-use of an installation when it is no longer needed for its current purpose. 

The cost of decommissioning may be considerable, and comes of course at the point when the project is no longer generating funds. Some source of funding will therefore be required, and this may be available from the profit of other projects, from a decommissioning fund set up during the field life or through tax relief rolled back over the late field production period. 

Decommissioning may be achieved in different ways, depending on the facilities type and the location. This section will also briefly look at the ways in which decommissioning can be deferred by extending the field life, and then at the main methods of well abandonment and facilities decommissioning. 

Late in the field life it is desirable to compress the 100 MMscfd for the example field downstream of the separator from 800 psig at 100°F to l.(XX) psig. An engine-driven separable compressor is available from surplus. The engine is rated for 1,600 hp at 900 rpm. Horsepower is proportional to speed. The compressor frame has six 7-in, bore by 6.0-in. stroke double-acting cylinders with a minimum clearance of 17.92%, a rod load limit of 25,000 lb, and rod diameter of 1.75 in. Assume k = 1.26, Z, -0.88, and Zd = 0.85. 

B/D facility was offset by accelerated production and shorter field life. 

Almost every area wilt produce water at some stage of field life many areas produce saltwater from the beginning. But the prolific Middle East fields have produced dry, salt free crude for many years. This is rapidly coming to an end as the reservoirs are taxed for more and more oil. 

Flow assurance engineers for a major energy company (Mehta et al., 2003) indicate that for a two year periods, one of their offshore gas flowlines operated well inside the hydrate formation region. The problem arose from increased water production (to >1000 BPD) over the field life, with limited methanol delivery. Their approach was to inject as much methanol as possible, in the knowledge that they were underinhibiting the system. Due to under-inhibition, there was a gradual increase in the pressure drop (A P) in the line over a period of about 2 weeks, indicating a hydrate build-up on the walls. 

This strategy was successful in extending the field life by almost 2 years. This is one key example of the risk management philosophy, enabled by operating experience on the platform. The hydrate plug prevention technique in this case study is time-dependent and should be contrasted with thermodynamic (time-independent) inhibition methods in Case Study 4 of Canyon Express and Ormen Lange. 

One theory advanced for the historical lack of concern regarding the infliction of pain on animals during the first millennium, or so, is that life for people of this period was often little better than their pets or the beasts of the fields. Life was basically short and hard and contained much pain and suffering. How could concern for an animal in agony be mustered when members of the family were suffering equally ... 

---