Appraisal of exploration prospects using extended well testing

Well testing setup for Hermod. An extended well test (EWT) was successfully planned and carried out on the Hermod Field, now known as Grane, commencing in July 1996, in order to address the outstanding uncertainties associated with the field following the exploration/appraisal program.

8harmpica

Hermod provides good example of EWT process

T. J. Leeson
The Expo Group

J. Barr, J. O. Selboe
Norsk Hydro

8harmpica

Well testing setup for Hermod.


An extended well test (EWT) was successfully planned and carried out on the Hermod Field, now known as Grane, commencing in July 1996, in order to address the outstanding uncertainties associated with the field following the exploration/appraisal program.

The EWT, conducted by a temporary production facility located on a semisubmersible rig, permitted data on the reserves in place, vertical connectivity, and fluid handling characteristics to be gathered successfully. An electrical submersible pump (ESP) was successfully deployed and operated on a temporary completion with subsea test tree (SSTT). Oil flow rates up to 20,000 b/d were produced.

The data collected has confirmed a minimum volume of reserves and has provided a basis-for-design for future processing facilities. In addition, extended well testing has been validated as an appropriate technique for appraisal of fields carrying uncertainties regarding coning behavior or fluid separation characteristics.

Background

The Hermod Field was discovered in 1991 in 128 meter water depths about 125 km from the Norwegian coast. However, after two wells on the main structure, a number of major uncertainties regarding the nature and economic viability of the field remained unresolved. These could be grouped into four main categories:

  • Lateral communication of reserves in place
  • Likely inflow performance and well productivities
  • Rate of water coning and its effect on productivity
  • Optimum solution for control of emulsions and separation of produced water.

These areas of concern gave rise to significant uncertainty with respect to the expected long-term well performance and production profiles for development wells. This, in turn, cast considerable doubt over the economic viability of recoverable reserves and the optimum solutions for well path planning and topsides facilities design.

These uncertainties would traditionally make the discovery a candidate for a phased field development. To reduce these uncertainties and to evaluate the potential for a full field development, it was therefore proposed to undertake an appraisal well test with an extended flow period, commonly known as an EWT.

This would entail drilling and completing an appraisal well designed to produce in excess of 15,000 b/d, flowing the well to a temporary production facility, and storing the conditioned crude in an ocean-going tanker prior to transportation to a point of sale. The sale of the crude would offset a significant proportion of the testing costs.

EWT advantages

EWTs offer the opportunity to gain reservoir and production data not available from a traditional, short duration, well drillstem test. The longer flow period provides a greater radius of investigation from the wellbore which, depending on the nature of the reservoir, can assist in identifying reservoir boundaries and proving up reserves.

Designing the well to accommodate high flow rates permits a higher drawdown to be applied to the reservoir, and this in turn, allows vertical reservoir connectivity and associated water and gas migration to be assessed.

Onset of water production provides the opportunity to monitor the foaming and emulsion forming characteristics of the produced fluids. Various techniques for managing these phenomena can then be trialed and optimized, providing valuable data for future topsides design and chemical injection requirements. This would be of particular importance for any development of Grane as the high viscosity crude (19 degree API) raised concerns regarding emulsion formation associated with water production expected later in field life.

General arrangement

In order to eliminate the cost of well suspension and re-entry, the testing program was to follow-on immediately after completion of the drilling phase. It was decided to utilize a conventional EWT facility with the well produced through a temporary completion and landing string complete with through-BOP SSTT to a modular process facility located on the drill rig.

Conditioned fluids would then be exported via a temporary low-pressure flowline to a moored tanker acting as a storage vessel. Produced gas would be flared from the rig, and produced water treated in the process facility to minimize the oil-in-water content, before overboard discharge to sea.

Storage and subsequent sale of the produced crude would minimize the environmental impact of the test program and provide revenue with which to offset a significant fraction of the program costs.

As it would be the first extended well test attempted in the Norwegian sector since 1991, adequate preparation was identified as a critical factor for a successful program and 11 months were set aside between initial conceptual discussions and planned first oil. Contracts for the main workscopes were awarded in January 1996, just 3.5 months before first oil was expected. The Expro Group had the responsibility for design, engineering and operation of the fluid handling equipment from SSTT to export from the rig.

This included provision of the SSTT, landing string, crude processing facility complete with emergency response equipment, produced water treatment, export pumps, and all surface metering and data reporting.

In order to guarantee the flow rates required to provide the necessary data, and to replicate the likely development well design, it was decided to complete the well with an ESP. To maximize the well control options and permit the rig to unlatch from the well in bad weather and then return to production without the need for pulling and rerunning the completion, it was necessary to provide an emergency quick disconnect from the SSTT complete with a wet mateable connector for the ESP power cable. This would be the first time such equipment had ever been deployed. The SSTT was designed built and successfully tested in less than four months in order to meet the project schedule.

The principle challenges within the project were identified as follows:

  • Induction and control of water production
  • Handling of high viscosity oil
  • Produced water clean-up and disposal
  • Design and provision of the SSTT.

Well, process design

The well was drilled from the Treasure Saga semisubmersible and completed with 7-in. tubing in 10 3/4-in. casing. The horizontal section was drilled with a 9 1/2-in. section close to the oil-water contact, in order to induce water production, and completed with 7-in. pre-packed screens.

The ESP was installed in the high-angle section close to the reservoir and provided with a bypass to permit production logging of the production intervals.

The process facility was designed as a two-stage separation process with a maximum liquid throughput of 20,000 b/d, and a maximum of 8,000 b/d of water production, and specialized defoaming internals installed in the separation train to minimize the need for injection of control chemicals.

Stable oil/water emulsions were broken using a electrostatic coalescer to provide an export quality of less than 0.5% BS&W, and produced water was cleaned to a maximum oil-in-water content of 40 ppm with hydrocyclones.

The facility design underwent an extensive hazardous operations analysis and a number of modifications were carried out to the rig equipment including hard-piping all the flare lines. In addition, the process facility included:

  • Liquid scrubbers in the gas flare lines to eliminate the risk of flaring condensed liquids
  • Continuous monitoring of the produced water discharge stream to monitor the oil-in-water content
  • A monitoring system on the steam side of the interstage heat-exchangers to detect any loss of hydrocarbons from the process stream
  • Installation of a deluge system to cover the hydrocarbon processing areas.

Finally, a full integration between the shutdown logics of the rig and production facility was undertaken with a number of levels of executive action. This was interfaced with the tanker via an executive telemetry link. Certification of compliance from Det Norske Veritas was required, and issued, to specification - PROD N. The facility was classed as a production installation.

High accuracy turbine meters were included as part of the facility to provide fiscal quality data, and continuous BS&W monitoring was added to ensure export quality compliance. All surface, and downhole, data was collected on-line and stored by a PC-based data acquisition system and transmitted in real-time via a satellite link to the operators office in Oslo. This proved particularly important when decisions were required regarding progression of the test program.

Test program

After some delay, principally caused by the sector-wide industrial action in 1996, first oil finally flowed on 21 July 1996. Within two days the potential problems of handling such a difficult crude were highlighted by the buildup of salts in the inter-stage heat exchangers, deposited from the produced free water/brine. This was simply remedied by injection of small volumes of potable water upstream of the separation process, and a maximum flow rate of 20,000 b/d was soon achieved.

A full test program involving production logging, downhole and surface sampling, and flow and pressure buildup periods was undertaken using the ESP as artificial lift to maximize production rates. The well had been drilled to encourage water coning to reach the wellbore after a short production period. As the water cut began to increase, a number of chemical injection trials aimed at optimizing emulsion and foaming control were carried out.

A number of production logging passes were undertaken and these provided evidence that the pre-packed screens appeared to be restricting the comingled flow of water and oil from the areas where coning was expected. Nevertheless, a maximum watercut of 11% or almost 3,000 b/d of water was achieved. By recycling of up to 6,000 b/d of produced water on surface, the separation process was tested to up to 50% watercut.

The surface facilities designed to separate the water were a success providing valuable information for design of the future topsides facilities. In order to maintain the water coning, it was decided to run the ESP beyond its normal operating envelope and this was done with success. However, on 12 September, the ESP shut down unexpectedly due to cable damage above the SSTT within the marine riser section. The last week of the test period, during water recycling, was performed without artificial lift.

Conclusions

Having collected the total data set required from the test and having produced about 490,000 bbl of salable crude without a lost-time accident, the operation was deemed a success. Minimum reservoir volumes in place were confirmed, as was the processability of the produced fluids.

In addition, a number of lessons were learnt for the future and these can be grouped together as follows:

  • Clear program philosophy and test objectives must be set early in the planning phase.
  • Early, and frequent, communication with the regulatory authorities is essential.
  • Design and implementation of the rig modifications required can be complicated and expensive, requiring choice of rig, and participation of the rig contractor at an early stage.
  • The auditing of potential rigs for EWT requires a different emphasis from that normally used prior to drilling operations.
  • EWTs provide an unequalled opportunity for evaluating the applicability of production systems and process facility options.
  • Integration of the marine facility (LP flowline, tanker etc.) is relatively simple so long as the system functionality is correctly specified and the proposed solution is suited to the particular marine environment.
  • The use of the EWT technique has proved to be essential in moving this prospect through to field development, and will be considered an attractive option for similar fields in the future.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.

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