These issues were all addressed during the EWTs. For example, wax deposition trials were conducted and oil/water emulsions formed and then separated by sea water injection into the produced crude stream.

On Mungo and Machar in the Eastern Trough Area Project, results from EWTs removed the original downside reserve predictions.

For Mungo, the magnitude of downside recoverable reserves was addressed as the key uncertainty (see table below). 'The results leave no downside,' Dave commented.

MUNGO RESERVES (MMSTB)
                    P90      P50     P10
Reserves pre EWT     26       71      15
Reserves post EWT    86      143     203 

The Machar test has been designed to investigate reser-voir performance under natural depletion and water injection scenarios. Although the test began as an EWT, at least in BP's earliest discussions with the contractors, it now quite clearly is a phased development as described in the DTI guidelines. Machar is a fractured chalk reservoir with over 1000 ft of vertical relief. As the crude is saturated, behaviour of the secondary gas cap was seen as a key uncertainty, followed by sweep efficiency in the water injection case. Initially, some seven million barrels were extracted under natural depletion and the test has recently been re-configured for the water injection phase. Initial results from the first phase suggest that the STOIIP can be increased from 260 to 430 million barrels.

Shared risk
'Goal alignment through appropriate shared risk and reward has been, and still is, fundamental to achieving the best business outcome,' Dave added. 'Our declared business objective is to find a means of ensuring payment both for ourselves and the contracting alliance is the same, that is, from oil sold to the refinery. There are, however, a number of caveats to such a bold statement. We have no intention of allowing a contractor to take inappropriate risks - for example to gamble on an outcome over which he has no control or only limited understanding. It is clearly not in anyone's interest for a contractor to put his business at risk in such a fashion.

'It must also be clearly understood that goal alignment is a two-way street. The operator must understand the contractor's goals and business drivers. Clearly, if the business is to be pursued in the spirit of partnership, the operator must take the contractor's objectives into account. It is unacceptable to expect the contractor simply to acquiesce to the operator's needs.'

The results outlined above illustrate the value of the EWT as a cost-effective tool for unlocking the development of some fields. At oil flow rates above 15mbd, the value of the produced crude will cover the operating cost of a typical EWT spread, including mobilisation and rig modification costs.

The industry and the regulatory authorities have both had to learn how to behave to allow these tests to happen and particularly how to cope with long lead times in an uncertain world. As evidence of the authorities' desire to help, one has only to look at the revised Guidance Notes on Procedures for Regulating Oil and Gas Field Developments issued in December 1993. Added Dave: 'It is clear that this is a step in the right direction towards allowing rapid appraisal and development of the smaller accumulations we will all be faced with in the future. However, more simplification is needed, both for field development consents and pipeline works authorisation applications.'

Dave stressed that an EWT is not simply an extension of drilling operations. 'Whilst we might talk about the possibility of industrialisation of EWTs and all that they may mean for us, the sheer scale of costs of the equipment and operations that need to be managed for success in an EWT make it imperative that they are treated and managed as projects in their own right.'

Dave predicted that we can expect to see between four and eight EWTs in European waters, including Norway, in the 1996 summer weather window. He questioned the industry's ability to perform successfully if it attempts to operate at the high end of this range - unless the contracting alliances are allowed the space to plan the operations. The major threat to success will be the availability of adequately trained and responsible people rather than the equipment needed for the work, he warned.

Dave sees three major issues that will affect the future of EWTs. These are: clear demonstration of the value of EWTs and what they may lead to; environmental issues, in parti-cular gas management; and cost containment and reduction.

In BP and throughout the industry, there is now a growing understanding of the value of the additional data generated from EWTs. The examples above clearly help with this.

Whilst prudent management can alleviate concerns over most of the environmental issues, the subject of gas management is unresolved. There is, as yet, no commercially or technically acceptable way of reducing gas flares to a minimum. Dave said that BP acknowledges the regulatory authorities' concerns and is taking a proactive stance to deal with the issue. A number of potential solutions are on the horizon but it will be some time before they can be considered viable for the relatively long-term production scenarios let alone for the EWT time scale. It is, however, worth noting that flaring from a conventional DST consumes energy at a rate that is almost an order of magnitude higher than that of the gas flared during an EWT, so this issue must be kept in perspective.

He continued: 'The cost issue is one that we have been trying to address with our contracting alliance partners. Whilst such ideas as rigless EWTs clearly can help, serious re-use of converted equipment in continuous or even semi-continuous programmes will also help to contain costs. This can only come about as more operators understand the true value of EWTs and we see the development of an EWT 'industry'.

'The 'one stop shop' concept will, in our view, help to develop this. We can envisage a future where the decision to perform an EWT will be made in the same fashion as the decision to run a DST. The 'super alliance' can offer the full range of services from E&A well planning, through construction and data acquisition to production.'

Indeed, the concept of transition from E&A drilling through a continuum to field development follows directly from this. One very believable scenario for the future of the oil and gas industry in the UKCS is where E&A drilling on small oil or gas fields always has the potential to move seamlessly through reservoir appraisal into production, with essentially no time delay from discovery to first oil production.

An extended well test was one of the key factors in giving Texaco the confidence to press ahead with the development of the Captain field, according to Joe Lach, principal reservoir engineer for the project.

It demonstrated that the field could be exploited using 6000 ft horizontal wells and electric submersible pumps - development concepts considered vital to recover the viscous, low GOR crude oil from the shallow, unconsolidated sand extending over a large area.

Joe explained to the audience in the panel session held before dinner and Dave Neely's talk that in April 1993 a 6000 ft horizontal well was successfully drilled and completed from the John Shaw semi-submersible rig and tested for a period of 90 days. A maximum production rate of 11,800 barrels per day was achieved through a purpose-built processing system with export via a 6" flexible pipeline to a dynamically positioned tanker.

Texaco worked with about a dozen contractors to gather the large amount of data required. Three pressure buildup tests were undertaken - after five days, about half way through the test and at the end - and the performance of ESPs and demulsifiers was also studied.

It will be essential for the economical development of Captain that reservoir fluid inflow is along the entire length of the horizontal section. Production logging via 1 3/4" tapered coiled tubing demonstrated that over 5000 ft of the well was flowing - thus endorsing the EWT well completion design.

The successful EWT together with results from nine other appraisal wells drilled during 1993 clarified and reduced the technical risks and uncertainty surrounding the Captain project. Subsequent progress has been rapid. Company sanction and final development option selection took place in autumn 1994 and detailed engineering began in October of the same year. Government approval was gained in January 1995 and first oil is scheduled for late 1996, with revenues generated from the first phase to be used to develop a second area of the field at the end of the century.

Speaking from a contractor's perspective, Tony Oldfield of Coflexip Stena Offshore recognises that EWTs do provide opportunities for new business. Most EWTs to date have been undertaken by operator/contractor alliances and, in the longer term, the information and confidence gained from these tests will hopefully encourage the phased development of more marginal prospects.

'The integrated services approach allows for the re-use of capital equipment and is extremely flexible and capital efficient,' Tony added. He gave an example of the semi-submersible Sedco 707 which has been used for an EWT/EPS. With a discrete processing package on deck, the rig can work either as a fully operational MODU or floating production unit if required.

Dynamically-positioned tankers are typically used for North Sea EWTs, but Tony argued that a moored tanker with a much lower day rate could be equally reliable and effective, when considered on a case-by-case basis. It is only when planning operations in the more hostile waters such as west of Shetland and all year operations that a DP vessel might prove essential.

Experience to date has shown that EWTs tend to be operated on very tight schedules, and Tony echoed the messages given by other speakers in stressing the importance of having clear objectives and teamwork. 'Without the project culture, an EWT becomes a simple drilling operation with production bolted on at a later stage and, as such, becomes exposed to high interface risks,' he said. He looks forward to the day where the progression from EWT to early production system to full life of field could be seamless.

Dialogue with the regulatory authorities and gaining the appropriate approvals is also of paramount importance. But herein lies a threat, according to Tony. The regulations surrounding gas production and flaring are certainly a limiting factor on EWT/EPSs. And current HSE requirements, such as preparing a full field operational safety case for the production facility, place a huge additional workload on the team. It is a challenge for all involved to work together to see how the regulations can be made more flexible while retaining a responsible and safe approach to developing the North Sea's valuable remaining reserves.

The DTI perspective

THE perception that the DTI is 'anti' EWTs is misconceived, said Simon Toole at the panel session, and he urged companies to talk to the Department about their plans at an early stage.

'We fully recognise the value of EWTs for gaining a better understanding of the reservoir or boosting confidence in a potential development in a way which is not achievable by conventional DSTs or logging,' he remarked.

An EWT is a fast track option, with the DTI committed to giving quick consideration to production consent applications. Simon reminded the audience that consent is legally required to produce irrespective of whether the production is flared - this requires additional consent. A DST is the only exception to the rule, where three to four days' testing will be allowed for each interval.

When considering an application for an EWT, the DTI wants to be convinced that the proposed project will improve understanding and confidence. Added Simon: 'Companies should set definable and realistic objectives with an achievable data gathering and analysis programme. Flaring is an area of growing concern. An EWT may involve flaring oil and invariably involves flaring gas, and we must be certain that this is justified by the benefit of the information gained.' In later questioning, he expressed the hope that advances in chemical engineering might provide a solution.

Clarifying the difference between an EWT and a phased development, Simon said that no longer term plan is required for an EWT, whereas a phased development calls for a short Annex B for the first phase and a management plan for phase two. A phased development plan would be required if production exceeds data gathering requirements or there is a danger of a sub-optimal development.