OFFSHORE REPORT

Elgin / Franklin HP / HT development in the UK North Sea

Overview of the world’s largest high-pressure / high-temperature development in 300-ft water, 150 mi east of Aberdeen, emphasizing development drilling completion before pressure depletion complicates that process

Joel Fort, Director of the Elgin / Franklin Project, Elf Exploration UK PLC

he Elgin and Franklin fields, located in the Central Graben area of the North Sea in 92-m (300-ft) water, contain important quantities of rich natural gas condensates (about 750 MMboe). The reservoirs (sandstones of the Upper Jurassic period) are deep (5,500 m) and sour, with abnormally high pressures, extreme temperatures – e.g., 1,100 bar (16,000 psi) and 200°C (392°F) – and significant levels of both CO₂ and H₂S. This article introduces the major challenges, particularly the high-pressure / high-temperature (HP/HT) conditions, means to overcome them and current development plans.

The development program is discussed and progress status is described. The project was 90% complete at the end of April 2000; it is on schedule, within budget and on track to achieve its objective of CAPEX below $3/boe.

Introduction

Elgin and Franklin fields are HP/HT accumulations located in the Central Graben area, in the UK sector of the North Sea, Fig. 1. Franklin was discovered in 1985 and delineated with two appraisals in 1988/89 and 1991. Nearby Elgin, discovered in 1991, was appraised with two further wells in 1992/93 and 1994. The close proximity of the two fields – within just a few kilometers of each other – provided the critical mass on which to build a sound / robust joint development. Thus, in February 1997, the coventurers entered into a Unitization and Joint Development and Operating Agreement for the Elgin / Franklin Unit Area.

Fig. 1. Elgin / Franklin location and Central Graben transport infrastructure.

Main reservoir characteristics are summarized below. Reservoir fluids are characterized as gas condensate, with one compartment of Elgin being particularly rich, containing about 1.7 sm³ condensate/10³ sm³ gas (300 bbl/1,000 Mcf), twice the liquid content of Franklin. The 3 – 4% CO₂ and 40 ppm H₂S impose additional metallurgical and processing demands.

The fluid, rock and pressure / temperature conditions yield field parameters for which there is little analogous experience. The pressure and temperature conditions found in these fields are near the extremes of current experience, Fig. 2. As a consequence, one of the major challenges development planning assessments faced was the ability to predict field production levels with sufficient confidence.

Fig. 2. High-pressure / high-temperature fields.

The impact of reservoir performance uncertainties are compounded by drilling challenges. Not only are wells very expensive, they need to be drilled prior to significant reservoir depletion, i.e., before significant production history will be available on which to base subsequent well location decisions.

Exploration and appraisal wells – requiring substantial time to drill and utilizing high-spec, state-of-the-art rigs – were very costly and confirmed that drilling costs would represent a major portion of the total development investment. The Elgin appraisal drilling program was conducted on the basis that wells would be retained for potential use during development. The two appraisals were deviated from adjacent surface locations to facilitate their later use for development.

Rig commitments have been made for the development wells, covering a firm period of 6-1/2 rig years and optional extensions. Present performances show that only two-thirds of the anticipated drill time will be necessary.

Fluid compositions impose substantial processing requirements, although these are not perceived to be unusual in the prevailing context of field development trends. They exhibit relatively high levels of C₂/C₃ components, which significantly influence processing systems and create additional challenges in the context of the fields’ offshore location. Fluids will be processed offshore to deliver commercial quality gas into a new export pipeline to Bacton and live condensate to the Forties system.

Recoverable reserves are estimated at 750 MMboe (half gas, half condensate), and development cost is expected to be $2.70 per boe.

Reservoir Challenge: Characterization And Performance Prediction

A sufficiently reliable prediction of reservoir behavior and performance is essential for field development planning. The extreme / unique characteristics of the two fields mean that substantial analogous experience is not available, and reliance must be placed on analytical methods, testing and analysis. For reliable analysis, testing has been undertaken under conditions that replicate in situ conditions as closely as practical. Lab equipment capable of operating at the extreme temperatures / pressures of the two reservoirs has been used to characterize fluid / rock mechanics properties.

Mercury-free PVT cells developed by Elf have allowed fluid properties to be characterized. These can be used at up to 1,500 barg and 200°C. Analyses have confirmed the rich liquid yields expected from these fields – Elgin in particular. Fig. 3 shows the HP/HT PVT window of the specially developed cells, compared to conventional cells.

Fig. 3. High-pressure / high-temperature PVT behavior.

Behavior of the sandstone hydrocarbon reservoirs will play an important role in field production performance. Reservoir cores have been tested under the extreme pressure depletion conditions, and permeabilities have been measured. The effects of declining pore pressure on permeability have been evaluated and suitable algorithms developed. Permeability is expected to decline, typically, to about 80% of initial conditions; but to only about 30% in some high-porosity samples, as pore pressure declines with depletion. As the reduction is greatest in rock that has the highest initial porosity – and thus permeability – the permeability reduction is not expected to have a major impact on ultimate recovery.

The most porous and productive reservoir layers could, of course, contribute most to well deliverability. However, these layers also tend to be the weakest and are most exposed to potential local wellbore failures under high-drawdown and depletion conditions. Rock-matrix integrity risks have been assessed based on extensive core testing; and perforation / depletion strategies have been developed taking into account expected reservoir rock behavior under the static and dynamic conditions expected over field life. Perforation of layers with maximum porosity will be avoided and drawdown rates will be managed.

Reservoir simulation models have been built for Elgin / Franklin, incorporating analytical data derived from the extensive suite of reservoir fluid / core analyses. These models are now being used to predict reservoir behavior with reasonable confidence.

Drilling / Completion Challenges

One of the major drilling control challenges for safely drilling wells in Elgin / Franklin is maintaining mud pressure in the wellbore at a sufficient level to offset encountered reservoir pore pressure, without exceeding fracture pressure of the drilled formations. Figs. 4A and B indicate typical pore pressures encountered in relation to overburden pressure and frac gradient. The very low margin between pore and frac pressure gradients below the high-pressure transition zone demands close and careful maintenance of dynamic mud pressures used to control the well.

Fig. 4. Pressure gradients in Elgin / Franklin fields, initially (A), and after production (B).

The substantial temperature gradients and varying formation properties contribute to these difficulties and make careful monitoring and correct drilling procedure control essential. Procedures required to ensure that proper controls are maintained require sufficient time spent both monitoring conditions and conducting drilling operations.

The key to drilling control is mastering mud Equivalent Circulating Density (ECD). This is achieved through use of a proprietary software called ECDELF, calibrated on Elgin / Franklin and using data supplied by PWD equipment.

It is also of prime importance to understand events occurring while drilling through the transition zone and the reservoir. Offshore crews must be trained to differentiate thermal effects, actual hydrocarbon influx and supercharging, to react in the proper way. Dedicated HP/HT procedures have been developed to address this issue.

    Casing wear. Another major challenge is minimizing casing wear to qualify the 10-3/4 ´ 9-7/8-in. casing for production duty. This is dictated by the need to have a production tubing as large as possible for deliverability and also by the need to minimize annulus pressure drop in the next drilling phase.

To achieve that challenge, great care is given to the well profile to avoid severe doglegs; and casing protector subs are used to minimize casing damage by the drillstring. The casing is monitored using a multifinger caliper survey, recorded when the casing is new (baseline) and at the end of the 8-1/2-in. drilling section. So far, none of the wells drilled have required a tieback; and all of the 9-7/8 ´ 10-3/4-in. casings have been qualified for production duty.

     Drilling costs. High-spec rigs are required, with correspondingly-high daily rates. Unusually-high service costs are also required. A typical North Sea HP/HT drilling campaign can be expected to cost in excess of £120,000 ($186,000) per day. Thus, typical development wells, including completion, can be expected to cost on the order of £25 MM ($39 MM), or more.

    Well equipment. Equipment development programs were jointly undertaken by Elf and operators of nearby fields with similar characteristics, to ensure equipment availability to allow each well to safely deliver maximum flowrates. At the time of the Elgin discovery, existing equipment limited the completion string to 3-1/2 in. Equipment and techniques have been specifically developed and qualified for the project to allow installation of 5-in. completion strings. Development and production plans are now based on the fact that future wells will be equipped with 5-in. strings, as casing wear during drilling operations has been minimal, thereby allowing use of the 9-7/8 in. as production casing, as mentioned above.

As a result of the high cost of HP/HT wells at the depth of the Elgin / Franklin fields, it has been imperative to optimize well numbers, locations and deliverability to a much greater extent than for conventional developments. However, optimizing well numbers – and incentive to minimize them – has to take into account impracticalities associated with drilling after reservoir pressure has significantly declined.

    Pressure-depleted drilling. The two fields will be produced through pressure depletion. Fig. 4B illustrates the impact of pressure decline on reservoir pore pressure and formation frac pressure. This figure illustrates the potential impact of reservoir pressure depletion on drilling after production has commenced. A successful drilling program into a reservoir with significant pressure depletion would require additional casing strings to cover the varying pressure conditions; and it requires a careful determination of pressure-transition locations. The Elgin / Franklin development sequence avoids the requirements for drilling into reservoirs with significant pressure depletion.

Drilling Program

The Elgin exploration / appraisal drilling program has demonstrated a mastery of the essential elements to deliver production wells safely; indeed, the initial discovery and two subsequent appraisals have been retained for potential use. The appraisal program has confirmed that good penetration rates should be achieved in reaching the high-pressure zone at about 5,000-m (16,400-ft) TVD, and that substantial well deviations can be achieved, Fig. 5. It has also, however, demonstrated that considerable time could be required to drill, core and test the deep, high-pressure sections.

Fig. 5. Elgin exploration and appraisal well profiles.

Drill time of the three Elgin exploration / appraisals has ranged from 300 to 400 days each. The accumulated experience, however, allowed – at the time of Project Sanction in early 1997 – planning the drilling campaign on the basis of an average 200 days to drill / complete. A 48-month drilling program was planned to deliver the seven producers for Elgin, including recompletion of two existing wells. A 30-month program was planned for five Franklin wells.

It is planned to complete all development drilling before any significant pressure depletion is expected, to avoid additional cost / drilling risks imposed by drilling in severely pressure depleted reservoirs.

Drilling Summary, Results

The major features, therefore, of HP/HT wells which influence development plans for Elgin / Franklin are:

• Long duration and high cost of individual wells – which means well numbers are minimized, but a relatively-long, overall drilling program will still be required.
• Restricted opportunities for drilling subsequent to production commencement, or for infill drilling – which means the drilling program must be initiated very early (effectively as soon as possible after Project Sanction) and that well location selection will be critical.

Energy stored in the highly-compressed reservoir fluids will be effectively utilized to deliver relatively high production rates through the completion strings now available. Currently, it is planned to produce Elgin with only seven producers, including two of the existing exploration / appraisals. Six Franklin development wells are planned. Well locations and well numbers will have been selected prior to any significant production history, and opportunities to supplement the initial development drilling program will be severely restricted.

By the end of April 2000, the two exploration wells had been successfully recovered, and ten development wells had been drilled, 30% ahead of schedule and, therefore, well below budget.

Elgin Well G4 – the first development well – was drilled, cored and cased to the Fulmar formation in 140 days, at a cost of less than £22 MM ($34 MM).

From there, the learning-curve effect can be seen clearly on Elgin, as shown in Fig. 6A and on Franklin, Fig. 6B. A typical well duration is in the range of 100 days – drilled and cased.

Fig. 6. Drilling performance to Fulmar sands. (A) Elgin field using Santa Fe’s Galaxy 1 jackup. (B) Franklin field using Santa Fe’s Magellan jackup.

Production Handling

Production handling requirements have also been influenced by the HP/HT conditions. Pressure energy in the reservoir has been effectively utilized primarily to deliver reservoir fluids to surface through a minimum number of wells. Although the pressure energy will largely be dissipated under flowing conditions to deliver the production to surface, the high shut-in pressure and the high-temperature conditions impose special production handling requirements to ensure their proper control. Primary impacts have been on production chokes, flowline sizes and ratings, and pipeline insulation.

Some residual high pressure under dynamic conditions can still be available during the early period of each field’s production. This pressure cannot be effectively utilized because of its short duration, and because the requirement to separate reservoir fluids into gas and liquid products requires pressure reduction. The production chokes will dissipate any excess pressure energy.

High fluid temperatures will exist at surface only in the early years of production, before Joule-Thomson effects related to gas expansion take over. For Franklin, higher flowing temperatures in the early years will preclude difficulties with hydrates or potential wax formation in steady-state operations. In fact, the excess heat will need to be dissipated by coolers in the process stream.

Velocity limits rather than pressure loss tend to control the sizing of individual flowlines between wells and production manifolds. Valve development has been necessary to provide the particular sizes required.

The interfield flowlines between Franklin wellhead platform and the central processing facility – the Production / Utilities / Quarters (PUQ) – at Elgin are rated for full temperature, but at a reduced pressure capacity. Two lines will be provided, and operate as a unit. An instrumented Overpressure Pressure Protection System (OPPS) will protect these lines from overpressure. Each line will also provide a source of pressure relief to the other line.

Temperature effects have a dominating influence on design of interfield flowlines between the Franklin satellite and the CPF at Elgin. Pipeline insulation is required in later years to ensure that reception temperatures at Elgin are maintained above acceptable levels to avoid hydrate and wax problems. The insulation material has to withstand the high Franklin entry temperatures (165°C). Suitable insulation materials have been identified, and a qualification program has been performed.

HP/HT Choke And Valve Qualification

An extensive testing program to qualify production chokes for the high pressures and temperatures existing in early field life was undertaken. One of the objectives on the first Elgin appraisal included field testing a production choke. The experience from this first test has led to further lab testing. Improved chokes were then successfully tested during the second appraisal, which has now confirmed that acceptable production chokes are available.

As for ESDV design, piping on the Franklin wellhead platforms will be rated to full-shut-in wellhead pressure to preclude need for a pressure relieving system to protect a reduction in downstream piping pressure ratings. This necessitated development of larger, 12,500-psi rated valves. A comprehensive program to qualify a 12-in. ESD valve for this service had to be conducted.

Processing

From a processing perspective, the HP/HT nature of the fields has imposed particular requirements, but these are within the capability and scope of conventional technology. Utilization of the high reservoir pressure energy was mentioned in the previous section. Unfortunately, effective utilization of high reservoir temperatures available in the early years of production could not be realized. Processing requires substantial cooling, and the excess heat will be dissipated. Significant heating is also required in the process, and this will largely be obtained by waste heat recovery from power turbines.

The CO₂ and H₂S contaminant levels influence process and material selection but do not call for unconventional requirements. The particular fluid compositions, particularly the C₂/C₃ components, influenced ultimate process selection and placed a significant challenge on the separation of reservoir fluids into gas and liquid streams.

As gas condensate accumulations, Elgin and Franklin fields require substantial processing to satisfy gas sales requirements and – partially as a consequence of this – gas compression requirements are also large. Elgin and Franklin fluids, being sour, also require substantial processing to remove contaminants, and satisfy gas / liquid specs while maximizing final product value. On a balance of technical and commercial considerations, the decision was made to process gas up to sales gas quality offshore.

The selected commercial gas process is indicated in Fig. 7. After initial separation, the gas is sweetened using an activated MDEA process. It is then dehydrated with glycol. Hydrocarbon dewpointing is achieved through expansion / cooling utilizing a turbo expander. A splitter is incorporated downstream of the LTS to further condition the split of light hydrocarbons between gas and oil streams.

Fig. 7. Elgin central processing facility block diagram.

Gas exported with this process will contain <2% CO₂ and <1 ppm H₂S. It will be within the Wobbe Index and GCV specs of the UK NTS (National Transportation System) and the Interconnector system for delivery on Continental Europe.

Integrated Development

The economic viability and motivation for development of Elgin / Franklin depends on their close proximity. The reserves base and synergies of a joint development provide the efficiencies necessary for an economically-robust project based on current product values.

Because these gas condensate fields require substantial investments in wells and relatively-extensive and costly processing facilities, economic development demands reasonably aggressive production profiles. However, the commercial gas market demands relatively-long plateau production levels. Integration of the Elgin and Franklin developments allows an effective compromise between these conflicting objectives by phasing the production and achieving economies of scale in the processing and transportation systems.

Elgin – the richest in condensates – will be produced first at a rate consistent with its delivery potential. As Elgin’s production rate declines, Franklin wells will be brought on production to maintain the gas production profile. In this way, early condensate production (on which project economic viability depends) can be maximized by Elgin production, and the gas plateau rates (on which the gas market depends) can be maintained by Franklin’s production.

Fig. 8A and B indicate typical gas and associated liquid production profiles. These are reasonable expectations, taking into account gas-swing and reliability factors, as derived from design capacities of 14.6 MMscmd (515 MMscfd) gas and 175,000 bpd liquids.

Fig. 8. Elgin / Franklin gas production profiles (A) and liquid production profiles (B).

Facility Layout

The overall field architecture is shown in Fig. 9. Because development wells need to be drilled before any significant production, drilling started immediately following project sanction, and the drilling program is to be isolated as much as possible from interference from other development activities.

Fig. 9. Elgin / Franklin facility layout.

Each field has its own dedicated drilling platform, physically separated from processing functions and with minimal production handling facilities. The Elgin platform is adjacent, and bridge connected, to the PUQ. Franklin’s platform is an unmanned satellite, connected to the PUQ at Elgin with flowlines and service umbilicals. This arrangement also provides an important safety feature, in that well hazards are isolated from processing, utility and accommodation functions, as well as isolating drilling activities as much as practical.

As a consequence of the drilling program constraints, particularly limitations on drilling into pressure-depleted reservoirs, there will, fortuitously, be only a limited exposure to simultaneous drilling and production (SIMOPS) activities.

The PUQ platform is a very large steel structure (about 38,000 mt) of an innovative design, i.e., a production jackup of the TPG 500 concept.

Conclusions, Project Status

The tools and methods developed over the past several years have been applied to confirm and validate early expectations of reservoir behavior with satisfactory confidence. Necessary equipment has been developed to allow robust well architecture and safe / effective production handling systems. At the end of April 2000, the fields’ development status was as follows: the two committed drilling rigs had accumulated 65 working months, the two drilling jackets were installed during the summer of 1997 to minimize the number of tiebacks at the mudline, the wellhead platforms decks were installed in July 1999 and the interfield flowlines were laid during summer 1999. Umbilicals / electric cables between the fields have been laid. The PUQ was the only element not yet installed offshore. It was to sail away to the field in early July.

The project was sanctioned in March 1997 on the basis of a new commercial gas export system shared with another HP/HT development located nearby – the Shearwater development. The Elgin / Franklin operator is also the development operator for this common gas export system – the SEAL (Shearwater Elgin Area Line) system (500 km long, 34-in. dia.). Fig. 1 describes the overall arrangement. The SEAL pipeline has been laid and commissioned, and was gas filled in late November 1999.

The information derived from well data has led to a 10% increase in reserves and a sixth well is now planned for Franklin.

The overall Elgin / Franklin development budget, including its share of the SEAL system, is in the range of £1,650 MM ($2,560 MM). At the end of April 2000, project progress reached the 90% mark – on schedule – and costs show an 8% trend downward compared to the approved budget.

Confidence is now clearly established that large industrial developments can be based on HP/HT-condition reservoirs. The Elgin / Franklin development will be regarded as a major contributor to this move and will establish an important new production area and a new infrastructure base for the UK sector of the North Sea.

Acknowledgment

The Elgin / Franklin project is a development operated by Elf Exploration UK PLC on behalf of itself and the following coventurers, whose support the author acknowledges: Agip (UK) Ltd., ARCO British LTD., BG Exploration and Production Ltd., Esso Exploration and Production UK Ltd., GDF Britain Ltd., British Borneo Oil and Gas Ltd., Ruhrgas UK Exploration and Production Ltd., Shell UK Ltd, and Texaco Britain Ltd. This article was prepared from the paper OTC 12117, written by the author and presented at the 2000 Offshore Technology Conference, Houston, May 1 – 4, 2000. This paper was part of a six-paper presentation on the Elgin / Franklin project, as listed in the bibliography.

Bibliography

Fort, J., "The Elgin / Franklin project: Developing the largest high pressure / high temperature fields in the world," paper 12117, presented at the 2000 Offshore Technology Conference, Houston, May 1 – 4, 2000.

Sexton, P., G. Rabary, P. Berthet and J. Guemene, "Velocity anistropy: Key to reducing reserves uncertainty in Elgin-Franklin deep high-pressure / high-temperature fields," paper 12121, ibid.

Humphreys, A. T., "Completion of large-bore high pressure / high temperature wells: Design and experience," paper 12120, ibid.

Walton, D. "Equipment and material selection to cope with high pressure / high temperature surface conditions," paper 12122, ibid.

Stirling, J. R. and J. C. Summers, "Transporting high temperature fluids: the Elgin / Franklin insulated bundle," paper 12119, ibid.

Hull, T. L., "High pressure / high temperature production: Completing the process efficiently," paper 12118, ibid.

The author

Joel Fort, Director, Central Graben Area Asset, and Director of the Elgin / Franklin Project, Elf Exploration UK PLC, is a graduate engineer from Ecole Centrale, Lyon, and Ecole Nationale Superieure des Petroles et des Moteurs, Paris. He joined the Elf Group in 1973, where he has held various positions in operations and projects in various countries, including assignments in Norway, France, Angola and the UK.