Extended Well Testing Boosts Prospects For Development Of Marginal Fields

Tom Leeson
Expro North Sea Ltd.
Aberdeen

The Ocean Guardian semisubmersible rig performed an extended well test for BP in Foinaven field West of Shetland. Early production systems are key to BP's development plans for a number of finds in the frontier area. Photo courtesy of Expro.

The future for oil and gas production in the North Sea appears bright.

However, to maintain production and profitability, operators must find ways of bringing smaller and more marginal fields on stream while reducing development costs.

Extended well testing (EWT) provides one route for both obtaining the data required to reduce the uncertainties-and thus the costs-of facilities design and reducing the uncertainties of reserves and productivity.

In the right circumstances, it provides the key to unlocking untapped reserves and reducing the overall costs of field development. EWT can provide the bridge between conventional appraisal testing and commitment to full field development.

The application of EWT may not be appropriate for all reservoir types, but as the size of discoveries diminishes and/or complexities increase, it provides a cost-effective route to prospect evaluation and reduction of critical uncertainties in future field performance.

There are many areas where improvement in data acquisition and analysis will provide returns, not least those of improved well test data quality and accuracy, seismic techniques, and more cost-effective drilling technologies.

EWT history

EWT was first used in the North Sea by Occidental Petroleum Corp. to appraise U.K. Birch discovery in 1988.

Since then, EWT has not been as widely utilized as might have been expected (Fig. 1 [19,991 bytes]), due in part to the increased expenditure commitment traditionally required prior to reaching total depth compared with a conventional drill stem test (DST).

In addition, the rising rig day rate and difficulties in obtaining suitable vessels/

rigs have reduced the opportunities for choosing this technique.

However, it has been instrumental in minimizing appraisal costs for a number of operators and permitting them to progress with field developments, for example: BP Exploration Operating Co. Ltd. with Foinaven and Schiehallion; Texaco Britain Ltd. with Captain; Norsk Hydro AS with Hermod; and most recently in the U.K. sector, Ranger Oil (U.K.) Ltd. with Pierce field, to be operated by Enterprise Oil plc.

EWT Objectives

Typically the principal objectives of an EWT are to:

Confirm the extent of reservoir connectivity around the producing well.
Confirm long-term well productivity.
Identify production chemistry and fluid processing issues and optimize solutions for future management.
Reduce the overall cost of appraisal programs.

Critically, the long EWT duration results in a very large "radius of investigation" of the pressure transient set up in the reservoir. The increased radius of investigation has a number of effects on the results of pressure transient analyses.

For instance, the calculated horizontal permeability results in a value averaged over a large portion of the reservoir, compared with short duration tests.

Also, the effect of nonpermeable boundaries deeper in the reservoir can be seen in the pressure transient analysis. Care should be exercised in interpreting nonpermeable boundaries such as faults, and other data sources such as 3D seismic should be investigated for corroboration.

The effect of constant pressure boundaries (gas cap or aquifer) can be evaluated. In addition, the significant production volumes achieved leads to information on depletion and in-place volumes and on the drive mechanisms that may be present in the reservoir.

In parallel, the flow period permits handling trials to examine the problems associated with wax and asphaltene deposition. Experimental programs undertaken to examine management methods including chemical injection can be used to optimize the design of future facilities; with significant potential benefits for life-of-field costs.

The extended flow period can also be designed to provide data on water and/or free gas breakthrough, providing valuable data for field economics and process design.

Depending on reservoir behavior and geometry, the volume of data gathered during an EWT-and the resulting radius of investigation-can be sufficient to reduce the number of appraisal wells required prior to commitment to field development, thus reducing the overall cost of appraisal programs.

Typical EWT facility

A typical North Sea EWT involves using a drilling rig as a temporary production unit, from which crude oil is transferred by temporary export line to an oceangoing tanker stationed close by (Fig. 2 [21,207 bytes]).

Tests can be undertaken with almost any type of rig; however, to avoid complication, this article refers specifically to working from a semisubmersible.

Fluids from a single well can be produced via a temporary completion, subsea test tree (SSTT), and a blowout preventer (BOP) stack and riser to the drill floor, in a similar manner to a traditional DST.

However, the prolonged production period provides the opportunity to consider a number of variations on this arrangement. Alternatively, the well can be completed with a tubing hanger and a production string through the use of an SSTT providing dual-bore access (Fig. 3 [18,453 bytes]).

The completion can then be retrieved or used as a suspension string depending on the results of the test program. This offers the option of larger bore completions providing opportunities for increased flow rates and revenue stream.

This technique significantly reduces the cost of reentry and recompletion should the well be included in future development plans, despite the subsea production christmas tree not being committed to or available.

This scheme has become the preferred route for completing development wells for a number of operators in the North Sea, including BP and Amerada Hess Ltd., and is applicable to EWTs.

Subsea tie-back

The well can be completed with a permanent or temporary subsea christmas tree and tied back to the rig via a flexible riser.

Although this increases expenditure on hardware, it offers the opportunity to test a second well simultaneously through the BOP stack.

In addition, a fast-track drilling program can be accommodated by employing simultaneous drilling (through the marine riser) and production (Simops).

The number of producing wells can be increased by tying multiple wells back in parallel or by employing subsea chokes and "daisy-chaining" wells with jumper flow lines between hubs mounted on production guidebases (PGBs).

The single riser is then connected to the end of the chain (Fig. 4 [26,614 bytes]). The hardware costs are minimized, and flow rate data for each well can be acquired with downhole flow meters. The facility now resembles an option that can be utilized subsequently, with or without modification as appropriate, as an early production system or first phase development facility.

Production facility

The produced fluids are separated, and the crude conditioned to tanker specifications in a purpose-built production facility mounted on the rig.

This facility is usually skid-mounted for ease of installation but should not be viewed purely as an upgraded well test package.

The separation train is usually designed to accommodate significantly higher flow rates (currently as much as 30,000 b/d of oil) than for a DST and customized to the test objectives. Such capacity is designed to provide sufficient drawdown on the reservoir to permit evaluation of vertical permeability and effectiveness of drive mechanisms.

A much more sophisticated control, alarm, and shutdown system is required often to be integrated with the well control and rig and tanker systems, to manage the hazards and increased risks associated with the extended flow period. In addition, many of the flow routes are hard-piped to reduce the number of potential leak paths.

Two-stage separation reduces the vapor pressure of the produced crude to permit it to be transferred, via export pumps and a low pressure flow line, to the awaiting tanker.

This not only reduces the hydrocarbon emissions by more than 85% typically but also provides the opportunity to offset the cost of operations through sale of the crude. For example, Ranger was able to break even after its £17 million ($27 million) test program in Pierce from the proceeds of the sale of crude.

Produced gas is routed to the rig burner booms, and any produced water is usually treated to reduce the oil content to an acceptable level (40 ppm or lower) rather than recombining it with the produced oil and routing to the storage vessel.

Storage tanker

The storage tanker is normally positioned outside the rig's operating exclusion zone of 500 m, in a downstream direction in the prevailing weather.

A flexible flow line is deployed from the rig, usually initially to the seabed, although floating or submerged arrangements can be used in deep water and returned to the surface at the point of connection with the tanker.

This connection can be made via any of the standard available loading systems, buoyed or otherwise, as appropriate. Although it may appear simpler to employ a dynamically positioned (DP) tanker, the additional charter costs are likely to more than offset the savings made in dispensing with deployment, recovery, and lease or purchase of a mooring system for all but short-duration tests.

The simplest of mooring systems is the anchor-chain type, and this concept has worked successfully in the U.K. and Norwegian sectors recently. For use in the North Sea, the mooring system must permit the tanker to rotate about the mooring connection in order to minimize the forces experienced in bad weather.

This then requires the flow line/riser to also accommodate such rotations. This can be achieved by inserting a swivel in the flowpath or by using a flow line of sufficient flexibility.

Although the number of turns able to be taken may be limited, research has shown that it is extremely unlikely in North Sea weather patterns for the tanker to be driven through an arc of more than 270°. In the unlikely event that it is required, the tanker can reverse the rotation with the assistance of a support vessel.

In order to permit the tanker to disconnect from the flow line in a controlled manner in an emergency, it is necessary to incorporate an emergency quick disconnect system (Eqcdc) to prevent environmental pollution. Such systems are readily available and can be set up to be manually and/or automatically operated.

Rigless alternative

Relocation of the process facilities to the deck of the storage tanker offers large potential savings in rig hire (Fig. 5 [20,499 bytes]).However, the effect of this is reduced by the need for additional hardware such as subsea well control and a high-pressure flow path to the tanker deck and the costs of modifying the tanker.

The process facility can be located on a simple structure on the deck of the tanker, and the use of a temporary, modular design will minimize modifications required to the vessel and permit the ship to return to crude-carrying duties.

The facility can be supported by utilities supplied from the vessel or be designed with integral utility packages as appropriate. In addition, the tanker must be modified to accommodate extra personnel to operate the plant, and this accommodation must be protected in order to offer a temporary refuge in the case of emergency.

Addition of a helideck will facilitate crew change-outs and provide an additional means of escape, and a flare stack or boom must be deployed to support the process facility.

These points are small in comparison with the conversion activities required for long-term deployment as an FPSO for field development, and therefore the costs are considerably lower.

The tanker can again be moored or positioned on DP. However, the use of a high-pressure flow line and riser to tie in to the well will necessitate the provision of a swivel in the flow path, unless weather conditions will permit a spread mooring, or a pipeline protection shutdown system is considered to provide sufficient integrity.

The flow line and the umbilical carrying well control signals to the subsea production tree from the control panel located on the vessel both require quick disconnect facilities. These should be designed to facilitate reconnection in a similar way to subsea emergency disconnect packages (EDPs).

To minimize costs if production from two or more wells is planned, the wells are daisy-chained to a single flow line/riser as described earlier. The cost of subsea chokes and the jumper flow lines and hub connectors will be considerably less than multiple risers.

Individual production data can be collected from each well by downhole flowmeters with the data transmitted to surface via electrical connections within the control umbilical.

Rig intervention is still required to complete the wells, install christmas trees, and to kick off and suspend the wells. Care should be taken over the scheduling of these and production operations in order to minimize, or eliminate, the risk posed by unattended live wells.

In order to permit well interventions without the need to disconnect the tanker, the tanker and any mooring system should be deployed without the projected rig anchor pattern.

Such a concept has not yet been deployed in the North Sea. However, assembly of a program of consecutive tests, involving one or more operators if necessary, may provide the catalyst to release the undoubted cost-reduction potential of employing such an arrangement. Until recently, the use of the FPSO concept for field development has been limited, but this is changing. It may soon be economic to consider using temporary floating production vessels for long-duration tests.

Project schedules

The simplest schedule for testing is to carry out the flow period immediately after completion of the drilling program.

This will also minimize the total cost of the operation.

However, as there may be a decision regarding proceeding with the flow test to be taken, based on logging and/or inflow test results, minimizing financial commitment prior to this point may be necessary. This can be achieved by planning for the rig to return to the well for the EWT operation at some later date.

There are a number of possible long-lead items that may govern the time before return. To design and procure a newbuild process facility could take as long as 6 months. Such a delay can be substantially reduced by committing to the cost of design and engineering prior to fabrication, as this is not a significant element of the overall cost.

In addition, it may be possible to utilize existing equipment, with minor modifications where necessary. Together, these can reduce the lead time on the process facility to 3 months or less.

A similar timescale is required to permit a suitable tanker to be chartered and the necessary modifications to accommodate a bow mooring and/or flow line connection. Conversion of the tanker to a temporary production vessel is likely to take significantly longer.

A number of specialist items of equipment, such as downhole monitoring systems, premium production tubing, subsea production trees, and mooring chain may affect the schedule, depending on the test configuration chosen and current availability.

The effect of choosing a particular arrangement should be evaluated on a project-specific basis.

Finally, there are likely to be a number of submissions required to the regulatory authorities. These are obviously specific to each governmental sector but usually cover the management of safety and the placement of temporary pipelines.

As these submissions do not entail equipment fabrication, it is possible to eliminate any effect on the schedule by commencing preparation early, for minimal extra commitment costs.

Delaying commitment to the temporary production arrangement until after initial tests on the well increases total expenditure, because additional rig time is required to suspend and then subsequently reenter the well.

This can be minimized by suspending the well with a production string in place and employing wire line retrievable plugs in tailpipe and tubing hanger.

The extra costs incurred in hardware and running the completion are more than offset by the subsequent saving in rig time. Subject to all the foregoing-and to vessel and rig availability-a delay of 3-4 months from completion of the drilling program to reentry and production testing can be taken as a reasonable estimate (Fig. 6 [27,468 bytes]).

Track record

Many successful EWTs have now been undertaken in the North Sea, and an excellent safety record established by the principle service suppliers.

The reduction in environmental effects owing to reduced flaring is supported by the good record of minimizing spills and overboard discharge of hydrocarbons.

However, the EWT technique is likely to grow in popularity only when costs can be reduced through radical advances such as use of a rigless arrangement.

In 1996, Expro North Sea Ltd. worked on four fields in the North Sea during the year, providing both fluid processing and subsea systems for tests in Hermod field for Norsk Hydro AS and the Pierce field on behalf of Ranger Oil Ltd. In addition, Expro provided subsea systems for tests in Aasgard for Den norske stats oljeselskap AS (Statoil) and in Clair field, west of Shetland, for BP.

This year, Expro will be involved in Statoil's EWT in Connemara discovery off western Ireland, which began in late June, and in Texaco's Mariner discovery in the U.K. North Sea.

Hermod field presented the greatest technical challenges in conducting an EWT. The field is in the Norwegian North Sea in 128 m of water. The field contains 19° gravity low GOR oil with high viscosity both at surface and reservoir conditions.

In addition, an expected early water breakthrough into the well could cause strong oil/water emulsions to form, as well as inducing a tendency for the fluids to foam in the surface processing equipment.

Moreover, the well was to be completed with an electrical submersible pump (ESP), requiring the subsea test tree to provide an Eqcdc for the pump power cable.

The process plant included the use of two-stage separation, electrostatic coalescer for water removal and emulsion breakdown, a hydrocyclone water treatment package for the removal of oil from water, and vortex clusters at the inlet of the separators for the control of foaming.

An SSTT was engineered and fabricated in less than 3 months. The tree was deployed successfully in July 1996 and operated continuously for 56 days without downtime. This was the first time such functionality has been specifically provided for an EWT by an oil field service company.

The well flowed successfully for a period of 54 days at flow rates of as much as 20,000 b/d to a locally moored tanker, which disposed of produced water at rates as high as 3,500 b/d, after treatment to less than 40 ppm oil in water.

The test also demonstrated Expro's Edge-X system, which allows downhole and surface data to be transmitted via satellite from the rig to the operator's office onshore for real time reservoir evaluation.

Conclusions

The cost-effectiveness of a particular test will be influenced by rig rate, oil price, flow rate, and the benefits of implementing new technology.

For a given field, the total cost of field development may be marginally increased by including an EWT.

Nevertheless, this is likely to be more than compensated for by the reduction in cost of development facilities as the range of likely production profiles is reduced.

The uncertainties surrounding the economics of the development of marginal fields can be reduced significantly, permitting the commitment to development to be made without potentially costly delays or further appraisal wells.

The financial commitments required prior to confirmation of the well logs and initial inflow performance can be minimized at little extra cost by delaying the extended production period until 3-6 months after the initial drilling program.

The preparation and planning required for an EWT is significantly more than for a traditional DST. Therefore, it is imperative that both project management and operations are undertaken by competent parties.

It may be rare to find individuals with experience of both well intervention and marine operations. However, it is critical to a smooth operation that the key managers are able to understand the interfaces between themselves and other parties. Critically, they must appreciate the overall objective of the operation: data acquisition.

Challenges

The real challenge to all of us is to provide a method for economically developing small and marginal fields.

In order to make EWT more able to assist in this process and more attractive to those given the task of evaluating current prospects, there are a number of areas with potential for improvement.

Cost reduction is always an issue, and use of or modification of existing equipment will help in this respect. However, the greatest gains will come from more radical approaches such as use of the rigless solution or extended flow from multiple wells.

There is concern about the continued flaring of produced gas, and although a number of solutions are available for gas disposal, such as reinjection or conversion to methanol, these require significant capital investment or are not economically attractive at this time. As environmental concerns increase, the need for a solution for this issue will become imperative.

The extension of well testing operations to include marine activities has increased the number of interfaces among service companies.

This has led to the potential for misunderstandings between parties whose constraints and drivers are not well understood by all involved.

An operation such as an EWT requires careful, competent management, and communications and project coordination need to be given a high priority.

The Author

Tom Leeson is currently floating production systems coordinator for the Expro Group, based in Aberdeen. After 6 years with Shell in Oman, the Netherlands, and the North Sea, he joined the group in 1995 and is responsible for integration of company products and services to provide temporary production and extended well test facilities. A graduate of the University of Birmingham, U.K., with a BS and PhD in chemical engineering, he is a member of the Society of Petroleum Engineers and a chartered engineer with the U.K. Institute of Chemical Engineers.