TECHNOLOGY, LESSONS LEARNED

NEI-N0818 NO9705 270 (LOflF-qkoZ/q3--jjj ONS OFFSHORE

NORTHERNSEAS

ONS CONFERENCE 1996 27-30 AUGUST

STAVANGER. NORWAY

Paper no. F6

Session:

TECHNOLOGY, LESSONS LEARNED

Paper title:

«The Bongkot field, Thailand»

Speaker:

Christian BladierTour Total, France

OF W DOCUMENT StWLNnH)

DISCLAIMER

Portions of this document may be illegible in electronic image products. Images are produced from the best available original document

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THE BONGKOT FIELD, THAILAND

by Christian Bladier

ABSTRACT

The Bongkot gas field is located offshore in the gulf of Thailand approximately 600 km south of Bangkok and 180 km off the coast, at a water depth of 75 to 80 m. It consists of a multitude of small geological structures where gas accumulations are found in multifaulted reservoirs. The gas is mainly characterized by a high CO% content (4 % to 50 %) and a low condensate yield (average of 20 Bbl per MMSCF). The gas reserves initially estimated at 1.5 TCP in 1989 were certified at 2.9 TCP in 1994 and could increase further.

In 1989, TOTAL in association with its future partners, conducted negotiations of a gas sales agreement, based on the uncertainty of the reserves estimate and the geological complexity of the field. A phased development was initiated in 1990 with a production start-up of so-called Phase I in July 1993 at a daily contractual quantity (DCQ) of 150 MMSCF/D, with subsequent increases to 200 and 250 MMSCF/D. The paper describes the principle of this development, solutions implemented for some of the technical challenges and related experience gained during the following years of operations.

From 1993, a Phase II development was also implemented to increase the DCQ to 350 MMSCF/D and the new facilities were commissioned end 1995. The paper compares the initial concept of this second phase outlined during the Phase I conceptual design with the facilities actually installed.

Finally, further possible improvements or new concepts for future developments are outlined.

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The Bongkot field is located in the deepest part of the Gulf of Thailand within Thai waters close to the boundary with neighbouring countries, Malaysia southward and Vietnam eastward. It is around 600 km south of Bangkok and 180 km off the Thai coast (Fig. 1). The field mainly produces gas which is sold to the Petroleum Authority of Thailand (PTT) and sent via the PTT sealine system to Rayong and Surat Than! provinces. The gas is mostly used for the generation of electricity.

1. HISTORY

The first petroleum concessions were awarded in 1972 to Tenneco and BP. In 1973, the first exploration well drilled by Tenneco was an hydrocarbon discovery. Several wells were then drilled by both the operators. In 1976, Texas Pacific acquired both the concessions and pursued the delineation works. Altogether, 23 wells were drilled by the successive operators. In 1988, the Royal Thai Government purchased the concessions and assigned PTT Exploration and Production to develop this gas field. In 1990, PTT Exploration and Production (holding a 40 % stake), TOTAL (30 %), British Gas (20 %) and Statoil (10 %) entered into a joint venture and became the concessionaire for an area of 3200 km2 around the Bongkot field. TOTAL has been appointed as the operator until July 1998, then PTT Exploration and Production should take over the operatorship.

The gas production started in July 1993 at a level of 150 MMSCF/D (4.2 Mm3/j) and successively raised to 200 MMSCF/D early 1994, 250 MMSCF/D mid 1994 and 350 MMSCF/D beginning of 1996.

2. ENVIRONMENTAL CONDITIONS

The climate of Thailand is tropical with monsoon influence, i.e. with a dry hot season from February to May, a rainy season from May to November and a relatively cool season from November to February. In the Gulf of Thailand tropical storms and typhoons can occur from October to end December. The air temperature varies from 22°C to 34°C.

The water depth in the Bongkot area is in the order of 75 m to 80 m. The sea temperature is in the range of 25°C-30°C at surface and 25°C-27°C at seabed. The 100-year conditions are 12 m for the maximum wave height and 42 m/s for the 1- minute mean wind while the 1-year conditions are 6 m for the wave and 18 m/s for the wind.

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3. IMAGE OF THE BONGKOT FIELD IN 1989

The first detailed conceptual studies of the Bongkot field development were carried out in 1989 with the available data : seismic 2D lines, seismic 3D survey (120 km2) conducted in 1977, in the Northern part of the field and results of the 23 delineation wells, 12 of them being located in the so-called initial 3D area (Fig. 2).

The field is covering an area of 100 km long and 5 to 15 km wide. The reservoir is made of intercalation of shales and sandstones of oligocene to miocene age deposited in fluvio-deltaic and coastal environment. The reservoir is also highly faulted. The hydrocarbon trapping is mainly structural and dependant on the faults. Gas and condensate accumulations are found between -1000 m (3300') and -2800m (9200'), gas and water reservoirs are intermingled. The limited extent of the sand bodies and the numerous faults, as well as the geometry of the field, have shown from the very beginning, that a large number of wells will be required to drain the gas in place. However, the reservoir properties are good, average porosity 21 % and average permeability 100 md.

Besides, the area is characterized by a very high geothermal gradient of 6°C per 100 m giving a reservoir temperature close to 165°C (330°F) at -2500m (8200').

As far as the hydrocarbon composition is concerned, CO% is always present (4 % to 50 %). The CC>2 content is usually increasing with depth and is in the order of 25 % at - 2500 m (depth close to the reservoir datum) ; however, anomalies were evidenced by the delineation wells with sand bodies showing CO2 content up to 50 % at shallow depths of around 1800 m. The condensate content is low and was estimated in the order of 12 Bbl/MMSCF as an average.

In 1989, the gas reserves of Bongkot were estimated at 1.5 TCF (42.5 Gm3) with possibility to increase after further delineation works. However, the difficulty to understand the origin of CO2 and its anomalous distribution in the reservoir, was recognized ; this could result in abandonment of gas zones because of high CO2 and reduction of gas reserves.

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4. DEVELOPMENT POLICY

Taking into account these uncertainties, the negotiation of a Gas Sales Agreement with the Petroleum Authority of Thailand and the future partners of the Joint Venture, were conducted in 1989 and early 1990, with the two following principles :

- commitment for a minimum daily contractual quantity (DCQ),- possibility to increase the gas deliveries if the field behaviour was satisfactory.

As a result, the Bongkot concessionaire was commited with an initial DCQ of 150 MMSCF/D. Then the concessionaire had the right to increase sequentially the gas deliveries to 200, 250 and 300 MMSCF/D, at their own decision. In addition, four years after the production start-up, the DCQ will depend on the gas reserve estimate up to a level of 350 MMSCF/D. The maximum CO% content of the gas delivered was fixed at23 %.

The same reasons which supported this contract policy, conducted to select a phased development for the Bongkot field. The first phase should minimize the investment but also allow to increase rapidly the production, should the field behaviour be satisfactory.

5. PHASE I DEVELOPMENT

The first phase of the development was designed in 1989 (conceptual studies) and 1990 (basic engineering). It is including three wellhead platforms, a central production platform, a living quarters platform and a floating storage and offloading unit (FSO) for the condensate (Fig. 3). The process facilities are designed for a maximum production rate of 300 MMSCF/D corresponding to the swing capacity of a DCQ of 250 MMSCF/D. The process scheme is very simple (Fig. 4). The effluent stream arriving to the production platform, goes to a first stage separator. The gas is then routed to two compression trains (19.5 MW each) to be compressed up to 110 bar (1600 psi). The discharge gas is dehydrated in a glycol (TEG) contactor before being passed through gas metering to a 32" export sealine. In parallel, the hydrocarbon condensate produced in the first stage separator is stabilized through two further separators. Inside the last separator, an electrical heater allows a proper control of the temperature and the vapor pressure of the condensate. The produced water separated in the frist stage and second stage separators is treated before being disposed to the sea. The necessary utilities are provided, in particular two turbogenerators (2.5 MW each) supply the electrical power.

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The three wellhead platforms are identical except that one of them (WP1) is close to the production platform and connected by a 16" pipe laid on a bridge ; the two other ones (WP2, WP3) are connected by 14" sealines respectively 3 km and 5.5 km long. Each platform has twelve slots and minimum facilities : test separator, chemicals injection. In particular, the two remote platforms have no permanent power supply. Twenty-seven production wells were planned to be drilled from the three wellhead platforms.

6. PHASE I TECHNICAL ACHIEVEMENTS

In order to minimize the initial investment and to maximize the gas to be drained, numerous actions and principles were implemented. The most important ones are described below.

Monitoring of the CO% content in the sales gas

The maximum of the CO% content in the sales gas was agreed at 23 %. Eventhough, it was estimated that the average €0% content of the field was slightly above this value, the offshore installation of CO2 removal facilities was discarded from the beginning of the conceptual studies. Because of the variable C0% content in the sandbodies, a close monotoring of the production with mixing of high CO2 with low CO2 zones or wells, was planned. As a consequence, a proper evaluation of CO2 content of the layers to be perforated in each production well had to be be carried out, either by direct measurements (RET) or correlations with other wells. In particular, the policy was that layers with CO2 content above 40 % would not normally be produced.

Well location and trajectory

Because of the geology of the field (numerous small sandbodies, gas trapping against tilted and intersecting faults), the production well trajectories had to be in three dimensions, in order to reach as many gas accumulations as possible (Fig. 5). The location of "targets" had to be defined by the interpretation of the 3D seismic surveys.

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Well drilling

The optimisation of the drillling operations to decrease the cost of the production wells was crucial for the overall development profitability since a large number of wells were expected to be drilled. As a consequence a batch drilling process was implemented. All the wells of a platform are normally drilled at the same time in three sequences :

- drilling of all the 17 1/2 phases and setting of 13 3/8 casing,- drilling of all the 12 1/4 and 8 3/4 or g 1/2 phases and setting of 9 3/8 and 7"

casings,- perforations and completion of all the wells with monotubing (3 1/2) and

multi-packers.

Corrosion control

Despite the high CO% content in the production stream, carbon steel was used for the wellhead platform flowlines and manifolds, the 14" sealines connecting the wellhead platforms to the production platform, and a large part of the piping of the production platform. The protection against corrosion is ensured by inhibitor injection. This could be implemented because of the TOTAL expertise. In particular, TOTAL has developed and permanently improved, since 1984, a software able to predict the corrosion and erosion rates, based on field data (90 cases), published works and internal research works.

Sealines and multiphase flow

The production capacity of the wellhead platform was designed for a range of 10 to 100 MMSCF/D with a peak capacity of 120 MMSCF/D. Based on hydraulic and corrosion control studies, a diameter of 14" was chosen for the sealines connecting the remote wellhead platforms (2.5 and 5.5 km) to the production platform. No separation being installed on the wellhead platforms, the sealines have to carry multiphase flow. Besides, because of the small extension of the gas reservoirs, a rapid pressure drop of the production wells was anticipated and a single gathering system was installed without segragating high pressure production wells and low pressure ones.

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Wellhead platforms

The 12-slot wellhead platforms were designed without permanent power generation or supply. In addition, no crane but only an air driven gantry crane was installed for lifting purpose ; the air being supplied by a work boat or supply boat when necessary.

Production platform

The production platform was designed as an independant platform form the adjacent wellhead and living quarters platforms. The additional cost for structure was balanced by the following advantages :

- identical drilling facilities and design, for the three wellhead platforms,- possibility of drilling wells while construction works were carried out on

the production and living quarters facilities,- simpler and independant design for each platform,- simpler safety systems,- increased competition at bid stage for platform fabrication.

From a process point of view, there is no hydrocarbon dew point control of the sales gas. Indeed, an analysis of the possible flow conditions in the 32" export sealine (180 km long) showed that proper operating conditions could be achieved even in case of multiphase flow at transient regimes.

A vertical flare was installed on the platform instead of a remote one on a tripod, with necessary equipment to prevent liquid carry over in case of wrong operations. This design was derived from a North Sea field experience.

It is worth also mentionning the oily water treatment performed by two rotary hydrocyclone units.

Despite the objective of minimizing the cost of the initial investment, provisions had also to be taken into account to allow possible capacity increase from 300 MMSCF/D (DCQ 250 MMSCF/D) to 400 MMSCF/D (DCQ 350 MMSCF/D). Therefore, space was kept available on the different decks of the platform, to allow the installation of a third compression train, a third turbogenerator, a second first stage separator (of reduced size), additional sealine risers and other process or utility facilities. Besides,

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the jacket and the topsides structure were designed to support the possible installation of fourth turbo-compressor in cantilever.

FSO

The floating storage and offloading unit for the condensate was built from a cut and converted tanker. Indeed the front half part (about 110 m long) of a tanker whose the rear part was destroyed by fire, was used. An integrated turret was set in the bow, to allow the transfer of condensate from the production platform and a permanent mooring designed for typhoon conditions. The FSO is moored at 3 km north of the production platform, and the condensate offloading to shuttle tankers is performed in a tandem configuration.

Quarters have been designed for a maximum of ten persons, the normal crew for routine operations being expected to include five persons.

Living Quarters Platform

The living quarters are similar to the quarters of the Alwyn North platform operated by TOTAL in the North Sea. They include fifty identical rooms with two beds plus a foldable one, each room having a pefabricated bathroom unit. This design duplication allowed to save costs for the small price of changing the usual design in the area.

7. PHASE I OPERATIONAL EXPERIENCE

The operational consequences of the principles implemented during the Phase I design are briefly commented below in the same order they were described in the previous paragraph.

Monitoring of the CO% content in the sales gas

This monitoring has been proved to be feasible and quite successful ; it is a permanent task. First, during the final logging of a new development well, a balance must be made between maximizing the number of gas composition measurements in the layers to be perforated to appraise accurately their CO% content, and minimizing the logging cost. A lot of work has been dedicated to improve the accuracy of correlations between wells, in particular by using a detailed interpretation of RFT pressure measurements, much easier and faster to perform than fluid sampling. The improvement of correlation

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accuracy allowed to decrease significantly the fluid sampling. Then, regarding the overall production of the field, an optimum must be found between gas deliveries at the highest possible CO2 content (close to the 23 % maximum) to maximize the recovery and gas deliveries at the highest possible calorific value (i.e. minimum CO% content) to maximize the current revenue.

However, it has also been evidenced that some significant gas accumulations with a CO2 content in the order of 40 % or above, will not be able to be produced by simple mixing with low CO2 content accumulations.

Well location and drilling

A lot of work has been also dedicated to the interpretation of 3D seismic surveys in particular to develop "direct hydrocarbon indicators". Three dimensional wells have been successfully drilled (Fig. 5). The average net pay of the development wells drilled during Phase 1 is three times higher than the vertical delineation wells drilled in the same area.

The batch drilling process was also successfully implemented and allowed to decrease significantly the drilling and completion duration from an average over 15 days per well at the start-up of the drilling campaign to 11 days at the end.

Corrosion Control

In addition to the routine corrosion monitoring, flowlines of high CO2 production wells were dismantled for checking purpose. All the measurements which were performed, have confirmed that the option taken during the Phase I design was the right one.

Sealines and multiphase flow

The start-up of remote wellhead platforms after a complete shutdown, appeared to be one of the delicate tasks of the offshore production team and was somehow underestimated. Indeed the slug catcher capacity of the first stage separator was only 9 m3. However, after a learning period, proper start-up procedures were defined ; in addition valves manually controlled from the control room, were installed on the production platform at the arrival of both the sealines conecting the remote platforms, to choke the sealine flow in case of arrival of large slugs. Anyhow, the process of restarting a remote wellhead platform, was always requiring several hours.

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Wellhead platforms

Because of the platform design with minimum facilities to decrease the cost, it was recognized from the beginning, that some risks were taken for the daily operation comfort but that the offshore operation staff will be innovative enough to solve the possible problems. This assumption was proved to be correct. However, the daily weather conditions appeared to be worst than expected and the servicing of remote platforms by supply boats is difficult about 30 % to 40 % of the year and helicopters have to be used during these periods, for transfer of personnel and material.

In addition, during drilling operations and more particularly during rig moves, the absence of crane on the wellhead platforms has contributed to increase the stand-by duration for bad weather. Indeed, drilling is performed with a rig installed on top of the platform assisted by a tender barge ; the cranes being on the barge, the lifting operations are sensitive to the sea conditions.

Production platform

The operational experience confirmed the soudness of the facilities design and equipment layout. A point worthwhile to be mentioned is the vertical flare which required a while before being fully accepted by the offshore team, the depressurization operations being rather impressive.

FSO

Quite a few difficulties were experienced during the first months of operations because of a few poorly designed equipment. However, after two years of operations and more than eighty condensate offloadings, neither lost time accident nor delay of operation was recorded, which is a proof of the soundness of the general design of the unit.All the routine operations are performed with a crew of seven persons, instead of five as planned ; the two additional member being a catering employee and a crane driver/deck foreman.In case of tropical storms or typhoons, the crew is evacuated to shore or to the living quarters platform, minimum facilities (level in the storage tanks, emergency shutdown, fire fighting actions) are kept alive on the FSO and the condensate evacuation from the production platform is maintained with telemetry control. The evacuation procedure

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was defined after the start-up of the field production. The telemetry which was not planned in the initial design was installed afterwards.

8. PHASE H DEVELOPMENT

The phase II development was initiated in 1993 almost at the same time as the field production start-up, to increase the gas delivery to 350 MMSCF/D with a peak capacity of 400 MMSCF/D. Three new wellhead platforms (WP4, WPS, WP6) were ordered and the conceptual design studies were carried out to upgrade the process facilities from 300 MMSCF/D to 400 MMSCF/D.

The definitive concept was endorsed early 1994 and the construction project was launched. The Phase II includes three wellhead platforms as mentioned earlier, with 18" sealines (respectively 6.3, 6 and 10.7 km long), a riser platform linked by a bridge to the production platform and a flare tripod connected by bridge to the riser platform ; later on two additional wellhead platforms (WP7, WPS) respectively connected with 16" and 14" sealines were added (Fig. 6). The riser platform is also supporting, in addition to the sealine arrivals, a new first stage separator with large slug catcher capacity (100 m^) and a condensate heater.

The wellhead platforms WP4, WP5, WP6 were installed offshore ready for drilling, during the first quarter of 1995. The riser platform and the flare were commissioned and started in December 1995. The two other wellhead platforms WP7, WPS will be installed mid 1996.

9. COMPARISON OF PHASE H DESIGN WITH PHASE I CONCEPT

The main differences between the design of Phase II facilities and the initial concept prevailing for the Phase I design are outlined below.

Sealines

18" diameter was chosen for the sealines connecting the new wellhead platforms WP4, WPS, WP6, instead of 14" as in the first phase, in order to increase the production capacity of the platforms on the basis of the results acquired during the Phase I drilling and to allow the connection of future nearby platforms.

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As a consequence, the difficulties experienced with the start-up operations of a platform after shutdown, could be increased with longer and larger diameter sealines ; the installation of a large slug catcher was therefore a requisite.

Wellhead platforms

The wellhead platforms are essentially similar to the first ones, except for the addition of a crane for the reasons explained previously. However, the platforms do not have permanent power supply similarly to Phase I. The power required for the crane, in particular, is supplied either by the drilling rig or by a supply boat, when necessary.

Riser platform

A riser platform was added to support new facilities and sealine arrivals, in spite of the space available on the production platform. Detailed studies showed that the cost of this solution was slightly lower than the cost of installation of all the new equipment on the production platform. Besides, it can be mentioned that the condensate heater is significantly bigger than expected during Phase I design, because the condensate production is about 70 % more than initially planned, with an average yield of 20 Bbl/MMSCF.

Flare tripod

A remote flare was added because the upgrading of the vertical flare on the production platform appeared to be not feasible.

10. FUTURE CHALLENGES

After the gas reserves were certified at a level of 2.9 TCP in 1994 which allowed to amend the initial Gas Sales Agreement and to bring forward the increase of DCQ to 350 MMSCF/D by eighteen months, the reserve estimate has been further increased and is currently in the order of 3.3 TCF. The conceptual studies of a Phase III development have then been carried out to increase the production capacity of the field to a DCQ of 550 MMSCF/D and a maximum of around 650 MMSCF/D, by mid 1998. This phase will include the addition of a third compression train, a third turbogenerator and process capacity increase, in particular separation and gas dehydration. New wellhead platforms will be also added.

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Several axes of technical improvement have been also evidenced or are already implemented. A few of them are outlined below :

Drilling of extended reach wells to increase the reserves drained by the same wellhead platform.Wells with monobore completion when the reservoir conditions are favorable (only one or two producing layers with significant reserves), to decrease the well drilling and completion costs.Horizontal wells, also depending on favorable reservoir conditions, to produce high liquid content zones.Small and cheap wellhead platforms to accommodate only a few wells, in particular for the development of the south of the field where gas accumulations are smaller and more spread apart, than in the rest of the field.Longer distance with multiphase production, to avoid the installation of separation facilities in the south of the field.CO2 removal facilities, possibly on remote platforms, and probably with membrane system, to allow the production of zones with high C02 content gas.

More generally, on account of the experience with the development of Bongkot field, as well as with many other field developments when increase of production capacity is necessary, more studies and innovative design are required for the initial production platforms in order to decrease the cost of addition of new facilities. How to add this new facilities which must be connected with the existing ones, while minimizing the interference between production and construction operations, minimizing production shut-down periods, and maintaining safe operations ? Knowing that answer to this question, must be given at a time when a minimum cost investment is required.

11. CONCLUSIONS

The development of the Bongkot field has required to overcome many technical challenges, which have been briefly described in this paper. Among the technical achievements, some of them were innovative, other ones were only improvement of known technics. A lot of them might be presently considered as normal practice, however, at the time of their concept in 1989-1990, they supposed acceptance of technical risks to make this development profitable.

The capacity of an operating company to make successful, safe and profitable field developments certainly comes from innovative designs, but also from improvements on

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a lot of minor points, acceptance of technical risks when the cost reduction can be significant, and then from day to day work and optimization.

ACKNOWLEDGEMENT

C. BLADIER after participating in conception of the Phase I development of Bongkot, was the Operations Manager of TOTAL EXPLORATION & PRODUCTION THAILAND from 1991 to 1995. He wishes to thank all the members of TOTAL and Bongkot Joint Venture staff who contributed to the conception and the implementation of the phases of this development. He would also like to thank the partners of the Bongkot Joint Venture, PTT Exploration and Production, British Gas and Statoil for their approval to present this paper.

REFERENCES

Bongkot gas field development by Alain Chetrit, ASCOPE, Nobember 1993, Bangkok.

Thailand's Bongkot field on stream in June, by Pierre Guyonnet, Asian Oil & Gas, September 1993.

Duplicating North Sea living quarters saves Gulf of Thailand platform costs, by Pierre Guyonnet, Oil & Gas Journal, May 3, 1993.

BONGKOT

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8" 00'

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r 40'

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BONGKOT FIELD IN 1989

102° 20' 102° 30'

ONS - AUG. 1996TEP/DEP/ETR - 3410-12

TOTAL

THAILAND BONGKOT FIELD FACILITIES PHASE 1

— ONS-AUG. 1996-TEP/DEP/ETR - 3410-13

TOTAL

Figure 3

BLOCK DIAGRAM OF PHASE 1Figure 4

Met

ers

TOTAL THAILAND BK-2-C

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Meters

ONS-AUG. 1996TEP/DDP/PAO ETR - 3410-15 TOTAL

TEP1US - AUG. 1996 —Fp/ETR ~ 3410-16