TECHNOLOGICAL IMPACT IN THE REDUCTION OF OPERATIONAL PRODUCTION COST

Castro, G.T. - PETROBRAS; Suslick, S.B. and Morooka, C.K. - State University of Campinas ABSTRACT

This paper shows the impact of technology evolution in the cost reduction on a

offshore oil production platform. The technology represents a very sensitive variable in most of projects, specially in deep waters operations. It is possible to find some information about effects of technology in investment reduction, but it is quite rare to find in the literature information covering the impact in operational cost reduction.

The methodology employed in this work has two parts. In the first part, a representative group of production platforms from Campos Basin was selected, then the data from the last three years of each group was analyzed, finding the cost contribution of each activity in the total cost. And, the second part involved the measurement of cost reduction impact for the main technological innovations in the most important activities.

Campos Basin was selected as a case study because it is the most important oil production region in Brazil. It is responsible for more than 70% of total oil production in the country and one important deep water production frontier in the world.

From the results in this study, many findings could be observed. Among them, it is concluded that the total operational cost of workover, subsea operation, workers and material transport and production platform represents almost 86% of overall costs in the present case, the platform automation is responsible for a 6% reduction in the operational cost, among others.

INTRODUCTION

Campos Basin, the main petroleum province in Brazil, is located in the north of the state of Rio de Janeiro in an offshore area with quite more than 100.000 km2. Subsea oilfields are between 70 and 140 km away from the coast line close to the cities of Cabo Frio, Macae and Campos, in a water depth which ranges 80m over to 2000 m.

Campos Basin exploration initiated in 1968 with first discovery in 1974 through the wildcat RJS-9A at Garoupa field. The first oil produced came from Enchova field in 1977. Since that, several technological challenges have been overcome. The completion’s record in Figure 1 indicates the technological evolution through this period.

Technological challenges was intensified with the 1973 oil crisis. The first offshore oil discovery in Brazil (1974) occurred just in the middle of the economic disruption, worsened by the country’s unfavorable external payment balance. Then, levels of oil price justified intensive exploration and production investments. Main reservoirs were discovered in deep waters, then investments in technological development needed to be done in order to produce those fields. COLLINGRIDGE et al.(1) described the similar trend in the North Sea, where the first field was discovered in the early 70’s and the first oil came on stream in 1975.

During the first part of the 70’s, the increase of reserves and production was guarantee due to high level of petroleum’s price. However, the excess of supply of some major traditional producers, following by prices decline and projections indicating slow grow of demand in the future(2,3), obliged the companies and institutions the adoption of mechanisms costs reduction.

The above mentioned trend motivated the creation of programs of technological innovations in offshore regions. Examples of such programs are "CRINE"(4,5) in England, the "NORSOK"(6) in Norway, "DEEPSTAR" in United States and "PROCAP" in the Brazil(7). Originally, the efforts focused in reduction of the investment costs, by now the innovations is also being applied to reduction of the operational costs. According with Skrede(6), there is a learning process in the organizations that tend to be very focused on the investments costs to build the facilities, but to be successful it is necessary to build projects with low operational costs.

The technological evolution can be evaluated by using different variables and effects and its main motivation for technical change can be changed with time. Many methods have been applied to assess the economic aspects of the technological programs(8,9,10). Considering such constraints, the achievements made in technology to guarantee the production in deeper waters or seeking to reduce the costs of investments will not be discussed here. This paper will focus in the reduction of operational costs resulting from technological evolution. In the literature studies regarding reduction of operational cost due to non technological evolution factors(11) can be found. However, this kind of analysis will be not considered in this work.

The present paper is divided in three parts. In the first part a scheme for classification of costs are presented, following by an analysis of sample data extracted from Campos Basin. The last part include the discussions of results obtained from the technology impacts on costs reductions in offshore operations.

COSTS CATEGORIES AND CLASSIFICATION

As the main objective of this paper is to study the technological development impact in the operational costs, it is necessary to give an overview of the main costs categories and their classification scheme. Although some categories of costs have precise meaning in the account system, these categories do not conduct to an efficient decision-making.

INVESTMENT AND OPERATIONAL COSTS

The total production costs in this paper includes investment and operational costs. Despite its simplification for not incorporated short-run costs effects, this classification is commonly adopted in the oil industry. The investments costs are those expenditures made to acquire a capital assets. The largest portion of investment costs is incurred to initially get the project started, where frequently production of petroleum does not still exist, generally that costs are depreciated during the estimated producing life of the asset (project). The investment cost curve behavior initiate with a pick-up, following by a sill, which reflects some expenditures made throughout the life of the field.

The operational costs are those that happen during the project-life. They are not depreciable costs and are used to maintain the whole process in operation. The main items of this costs are personnel, consumable (diesel, lubricating oils, etc), maintenance and workover. The operational cost curve is almost a constant value during the project, with a reduction trend after a certain learning process is acquired, and there is a pick-up in the abandonment phase. Operational cost fall in two classes: fixed and variable costs. Fixed

costs (labor, materials, supplies, etc) are consumed directly in the production process and it is proportional to the level of production volume.

As described by DE WART(12), the investment costs have a great influence in the operational costs and between them exists an inverse relationship. It means that larger is the investment costs in a project, smaller tend to be the operational costs during the useful life of this project. The inverse relationship is also true.

Therefore the best project in terms of costs is the one that deal with the investment and operations costs of a project achieving the minimum present value(or maximum benefit-cost ratio). This decision goes by several factors, as capital disposable of the company during the time, among others.

MAIN OPERATIONAL COSTS IN A STABLE SYSTEM

The methodology of the operational costs classification can vary from company to company, even so, in general they tend to have a quite similar classification. As the objective of this work is analyze the operational costs reduction, it is necessary to define a basic classification to permit the comprehension of the data. Preliminary operating costs are generally more difficult to estimate than investment costs for most petroleum operations. The relative uniqueness of each petroleum operation with respect to equipments, labor intensity, location, operational philosophies, etc. makes the estimation of operating costs most difficulty. For these reasons, this paper use a classification scheme as closest as possible for those commonly used in the petroleum industry. Transport = Costs of transport means the value spent with transport of loads and personnel, using a marine or aerial way, between the port or base of the company operator until the platforms. Workover = Workover costs include the rigs, the personnel involved with the operation, and others. Operational workover cost that has as objective the reservoir different from the originally produced will not be computed in this cost, and in this case, for being a new area, investment cost will be considered. Subsea = It will be considered subsea costs in this classification all the operations that involves maintenance of equipment that are inside the sea, or "wet", excepted the workovers. Manifolds’ inspections, leaks repair in hydraulic lines and inspections in jackets of fixed platforms are some examples. Reform = In some production platforms are necessary some recovery works or restoration of some equipments or areas, services as maintenance painting and improvements in the performance of the process are some of the possible facts that incurred in this kind of cost. Maintenance = Several non routine services of maintenance are included in this classification, as revisions in generators, crane, turbo-compressors, and other equipments, generally accomplished by production platform non-resident personnel. Production platform = Are listed in this item the whole part of maintenance to keep the production platform operational condition, such as personnel, chemical products used in the production process, maintenance of the several systems, among others.

TYPICAL DISTRIBUTION OF THE COSTS IN PRODUCTION PLATFORMS

Considering the several cost types, it is necessary to define a typical production platforms cost distribution. As the objective of this paper is to detect the reduction of the operational cost, it is studied the cost types that represent the largest influence in the total operational cost. Considering a Pareto’s approach, it is feasible to identify the areas of technological progress that will provoke the largest impact.

To obtain a representative data sample, it is used the model created by VARGAS & COUTINHO(13), that divides the Campos Basin development in four phases as follows:

Phase 1(08/77 to 07/83) – This initial phase were based on semi-submersible platforms called Early Production Systems (EPS), all the platforms of this period already left the location.

Phase 2(08/83 to 08/90) – This period is characterized by the installation of fixed platforms and the production technology consolidation with semi-submersible platforms, that

became more complex and changed the original name to Floating Production Systems (FPS).

Phase 3(09/90 to 06/95) – Characterized by the development and consolidation of the deep water technology and the giant fields production through FPSs.

Phase 4(07/95 to present) - Production peak increase phase using FPSs with great process capacity.

DATA EVALUATION

The distribution of costs is depicted in Figure 2. In order to guarantee an unbiased sample, it is selected data from a fixed platform of the second phase in the three year period (2F97, 2F96 and 2F95), a semi-submersible of the same phase (2S), a semi-submersible of the third phase (3S) and a semi-submersible of the fourth phase (4S). The main trends in the Figure 2, can be summarized as follows: • the maintenance costs increase with the life of the platform, and in the fixed platform the

portion of maintenance costs is larger than in the semi-submersible. • the reform costs show the same trend of the maintenance, and the difference among the

fixed and semi-submersible platform is still larger. • the workover and subsea operation costs have an inverse trend, decreasing its

percentage weight with the increase of the life of the platform. The reason for the small percentage of workover and subsea operation in the first year of production of the fourth phase semi-submersible is because in the startup phase the majority of these expenditures are considered capital investment and not operational costs.

• the sum of the costs classified as production platform, transport, workover, subsea operation, represent 86% of the total operational costs. Comparing yearly the total cost for each platform in Figure 2, it can be noticed that in the

newest platforms the importance of the workover and subsea operation costs tends to be similar of personnel cost.

The distribution of costs for each production platforms along the years (Figure 3) indicate that personnel's costs generate the largest impact with an increase trend as the platform gets older. Based on these data, it can be noted that actions to promote the reduction of personnel, workover, subsea operation and transport costs, will probably have more effectiveness in the reduction of the operational cost.

BHANU et al.(14) presented similar cost distribution for fixed platforms operating in India (almost the same age of 2F), where workover, maintenance and partial maintenance executed in the production platform reached about 50% of the total cost.

AUTOMATION TECHNOLOGICAL IMPACT

Several actions have being taken to optimize personnel's cost in the whole petroleum industry. Reduction of hierarchical levels, functions with multiple skills (operate and execute maintenance) are some examples of managerial actions that allowed improvements in this area. Even so, it can be considered the industrial automation as the contribution of the technological progress with a big impact in this sector.

In Campos Basin, the automation started in the fixed platforms, with prevailed technology at that time (1983). This system had a local pneumatic control and a control room with dedicated panels (shut-down, fire, and gas), all the electric information was centralized in these panels. This previous system had some disadvantages as: great amount of cables; local pneumatic control, which generates a lot of maintenance and keeping an operator for each operating system; use of semi-graph panel, big and very expensive, with little modernization options, among others.

In 1987, with the implementation of the Northeast Pole, some technological improvements were introduced. The main implementations were the control of mesh by electronic devices centralized in a control room and interlock of safety for programmable logical controllers.

A rapid increment of technological developments for Campos' Basin is observed beginning 1992 with arrivals of deep water platforms. These new concept production platform

systems used new technologies such as remote units for data acquisition with drastically reduced amount of cables for the control room; control of mesh for programmable logical controllers; standardization of the systems allowing better use of the human resources; no use of semi-graphic panel now using graphic stations with supervision software, among others.

Recently, the improvements introduced by problem diagnosis system MODIG (Diagnosis Module), system based upon "knowledge" previously "learned", facilitates to make the previous diagnosis of a problem, and it guides the operator to take preventive actions, avoiding and isolating problems. This system, in a vessel separator for oil production, screens several variables and it can detect the beginning of a separator level oscillation. It analyzes the oscillation and it gives automatically the diagnosis of a eventual abnormality in order to help the operator, avoiding an eventual high or low level shut down.

New production platforms in Campos Basin are designed with an advanced automation system. When the improvements justify the investment needed, the oldest platform systems also has been modified and new automation systems has been introduced.

CASTRO & PLATENICK(15) compared the automated platforms (advanced systems) with the no or little automated platforms in Campos' Basin. In this work, the ratio of number of employees divided by the oil process capacity was used to allow comparisons with numbers of employees independent of the size of the platform (Figure 4). It can be verified that the automated platforms have proportionally 20% less people.

In conclusion, it is observed that 47% of the total operational cost is due to "platform production costs" (Figure 2), and in the other hand, personnel's cost represents 54% of that amount (Figure 3). Then, it is possible to conclude that the industrial automation allowed an average reduction of 5% in the total operational costs. Other advantages such as the operational efficiency and safety increases are not included in the present study.

WORKOVER AND SUBSEA OPERATION TECHNOLOGICAL IMPACT

As already shown in the data analysis, the costs classified as workover and subsea

operation represents 25% of the total operational costs. Several technological developments has been carried out in this area, Main developments are described, as follows.

CONCEPTION OF FLOATING SYSTEMS OF PRODUCTION

The Campos Basin first production system in operation, the Enchova Early

Production System, consisted of a semi-submersible platform with a very simple processing plant (the gas was flared). Only one well was produced and the production stream flowed through a subsea test tree (EZ tree) suspended by the drilling rig, inside the blowout-preventer (BOP) stack. It used a drilling riser and a conventional surface tree at the rig floor. After processing, the crude was transferred through a floating hose to a nearby moored tanker.

This same system was enlarged with the use of another semi-submersible, and the first satellite well, using a wet christmas tree, a flexible line and riser in free hanging configuration.

The second production system was Garoupa/Namorado, that consist of eight wells with dry completion trees, enclosed in an atmospheric Well Head Cellars, connected to a atmospheric manifold with two botton-articulated towers, one to produce to a processing ship and the other to offloading. This system presented some problems, like a bad towers performance, that ended with a high operational cost.

The present conceptions have a tendency to produce many wells (distributing the operational cost of the platform among them), through flexible risers and much more efficient submarine systems. That technological evolution was fundamental for the development of the deep water fields in Campos Basin(16).

PROBLEMS WITH PARAFFIN Producing wells from waters even deeper and more distant from the production

platforms, thermal changes along the pipeline from the wellbore at the sea bottom to process plant in the surface, the temperature difference between crude oil inside pipeline and the sea water outside causes the beginning of paraffin deposition in the production lines. This kind of problems may clog the line, and with the continuos diameter reduction, can provoke the interruption of production.

The solution for the first case of blockage was the line substitution, generating the following operational costs: around US$ 1,000 per meter for substituting production flexible line, and about US$ 50,000 per day for pipe laying support vessel to pick up the clogged line and lay a new flexible line. If it is considered an operation with a well 1 km distant from the platform during one week, it would provoke a cost impact of US$ 1,350,000. Moreover, if 2,5 interventions per year is necessary, this operation would spend about US$ 3,5 millions per year per well.

In 1992 a process to dissolve the paraffin formation was developed in order to clean the production line (SGNTM). This system is based on a exo-thermal chemical reaction(17). An intervention with SGN has an average duration of one day and it costs around US$ 70 thousands. For the same well mentioned before, if it is needed five operations with SGN per year, it implies in a cost reduction bigger than US$ 3 millions per year for each well.

The definitive solution developed for almost eliminate this operational cost is the thermal isolation of the production lines, that reduces the rate of paraffin deposition and the development of several pig types to remove the paraffin formation periodically from inside the pipelines.

REDUCTION THE NUMBER OF WELLS

Several reasons, such as problems with DHSV and leaks in hydraulic lines, can

conduct to the need of workovers or subsea services. Therefore, all technological evolution that reduces the number of wells in a project tends to reduce the workover and subsea operation costs, and in consequence several hundred thousands dollars per satellite well can be saved.

Horizontal and multilateral wells are examples of technologies that reduced the number of wells, then the use of those reduces operational cost. As this reduction depends of the project for each field, it is very difficult to measure the impact in the operational cost.

FLOWLINE CONNECTION SYSTEMS AND LAY-AWAY COMPLETION

The connection systems and the lay-away completion methods had a great evolution,

besides turn viable produce wells in deep waters, it allowed a reduction in the time of the operations and the number of equipments such as ships and rigs involved, which reverted in a large operational costs reduction.

To better reach deeper waters, the lay-way guideline completion method was developed. Few years later an improvement, a lay-way guidelineless, was tested with success, but the method still requires the presence of both completion rig and the pipe laying support vessel at the same time and at the same location, which may led to eventual delays.

The new vertical connection procedure was successfully tried out. This system allows to connect flexible pipes direct to any subsea equipment in deepwaters, and utilization of a guidelineless methods with dynamic positioned vessels are required for this case. This operational procedure was designed with three main purposes: to provide an alternative for second-end connection, to eliminate the need of simultaneous operation of two equipments and to enable the pipe laying vessel to make the flowline connection, instead of depending on the drill-string of a dynamic positioned rig(18).

The horizontal christmas tree is other advance in technology which reduces costs. For this christmas tree it is allowed to make workover without removing the tree. Then, the time of intervention is reduced.

These new methods, saving time by using of rigs and ships for interventions, may represents an important savings in the operational cost.

TRANSPORT TECHNOLOGICAL IMPACT

The transport consume around 15% of the operational cost and has logistic importance. The transportation has a support role for other core activities in the plataforms. So, the reduction of transport costs is very closed with the reduction in the main costs, production platform, workover and subsea operation.

The transport costs can be divided by activity type, as subsea operation, workover, production platform and others.

The data analyzed in the present study indicated that the transport for production platform has an average impact of 35% on the total cost of transport (Figure 5). The impact of personnel’s transportation varies from 70% to 35% of the production platform transport cost (Figure 6).

In the following, linear relationship for the costs are considered. 15% of the total costs are taken into account for transport (Figure 2) where 35% of this amount had been spent with the activities for the production platform (Figure 5), and 56% of this production platform transport cost has been used to worker’s transport (Figure 6). With these considerations, it can inferred that the cost of the production platform personnel transport represents about 3% of the total cost. As in an automated platform there is less 20% people, it can be concluded that impact on automation will generate approximately 1% in reduction in the total operational cost. As shown in the Figure 5, almost 47.5% of the transport costs are relative to personnel, equipments and others materials for provide workover and subsea services.

Therefore, the reduction of the operational costs of transport, obtained with technological innovations, happens mainly with the reduction of the demand sectors (production platform, workover and subsea operation).

The use of supply boats with dynamic positioning is a rare example of particular technological evolution in transportation. This technology innovation creates an increase in operations efficiencies, allowing a 15% of reduction in the cost of load and water transport, even considering a higher daily rate than that for conventional supply boats.

OTHER ITEMS FOR REDUCTION OF OPERATIONAL COSTS

Fortunately the reduction of the operational costs is not limited to that main items.

The following are examples of other items that could be considered. BOOSTING SYSTEMS

Electrical submersible pumps for satellite wells, subsea multiphase pumps, subsea

separation systems, among several other innovations are empowering an additional energy to the produced oil and gas, between the wellbore and the surface production unit. It make possible the production of wells more distant from the production platform unit which will contribute to reduce the total number of platforms needed in a new project. SUBSEA MULTIPHASE FLOW METER

Subsea multiphase flow meters has been developed for petroleum industry use

during the last years. As precise data about real flow conditions at the wellhead during the oil production can be measured, oil elevation process can be estimated more precisely, and it can increase elevation process efficiency such as the gas lift. It also represents a potential operational cost reduction, because it can eliminate the well test flowline (avoiding pig operations) and a test separator vessel (avoiding maintenance and personnel costs).

NEW MATERIALS AND EQUIPMENT PERFORMANCE

The use of new materials optimizes and improve the quality and resistance of equipments (avoiding reforms and restorations). The equipment performances are also other item where technological evolution has an significant impact in the operational costs reduction. Even so, as it was described in the analysis of the current costs (Figure 2), maintenance and reforms are not the areas that cause larger operational costs impact.

CONCLUSIONS

The major development in oil technology is the increasing ability to operate in very

deep waters beyond the continental shelves. It could be possible due to improved success rates to find oil reservoirs and reductions on exploration and production costs obtained with introductions of the new technological innovations. A great deal of industry research continues on ultra deep water study and how to control and reduce costs in the operations and achieve a high productivity of wells. This trend will probably continue in the near future, due to the low oil prices trends and the sophistication and availability of technology developments.

Based on the studies carried out, classifying costs according to categories presented and considering Campos Basin platforms shown, it is concluded that the production platform costs represents 47% of total operational cost. Considering the workover, subsea operation and transport costs achieves 86% of total operational cost.

It is also concluded that the recent technological developments has also significant impact in the total oil production cost where automation represents 6% in cost reduction from total operational cost, paraffin deposition control represents a cost reduction of more than US$ 3 millions per year per well, workover and subsea operation have been saving millions of dollars per year for each well. Technological innovations as horizontal wells, boosting systems, among others, reduces the number of platforms and implies in a great impact in the total operational cost.

ACKNOWLEDGEMENTS

The authors wish to thank the colleagues from the E&P-PETROBRAS for their contributions, support and cooperation. Thanks are extended to PETROBRAS for permission to publish this paper. REFERENCES 1. Collingridge, D., Genus, A., James, P.: “Inflexibility in the Development of North Sea Oil” Technological Forecasting and Social Change, no.45, pg.169-188, 1994. 2. Zaid, A.M., Whitman, D.L.: “Oil Supply and Demand Analysis: A Price Forecast for the Post-Iran-Iraq War Period”, SPE 18916 SPE Hydrocarbon Economics and Evaluation Symposium , Dallas, Texas, 9-10 March 1989. 3. Al-Jarri , A.S., Startzman, R.A.: “Worldwide Supply and Demand of Petroleum Liquids”, SPE 38782 1997 SPE Annual Technical Conference and Exhibition , San Antonio, Texas, 5 – 8 Oct. 1997. 4. S.L.Smith.: “The Harding Field : A Low Development Cost per Barrel Concept Becomes a Reality”, SPE 30359 Offshore Europe Conference, Aberdeen, Scotland, 5-8 sept. 1995. 5. Kemp, A., Stephen, L.: “Sustaining the Viability of the UKCS in the New World Enviroment”, SPE 30359 Offshore Europe Conference, Aberdeen, Scotland, 5-8 setembro 1995. 6. R.O.Skrede.: “Ekofisk II – Planning for Low Operating Costs Through Lifetime”, OTC 8655 Offshore Technology Conference, Houston, Texas, 4-7 may 1998. 7. Beltrão, R.C.: “Cost Reduction in Deep Water Production Systems”, OTC 7898 Offshore Technology Conference, Houston, Texas, 1-5 may 1995. 8. Furtado,A.T.:“Petroleum and Technology Policy: What we have to learn with the Brazilian and French experience?” Thesis, Institute of Geosciences, Unicamp, 1995, 226p.(in portuguese)

9. Bach,L. Lambert,G.: “Evaluation of the economic effects of large R&D programmes: The case of the European space programme”, Research Evaluation, v.2,no.1, 1992, p.17-26. 10. Freitas, A.G.:“Technological capacity in deep-sea productions systems: The case of Petrobras”, Dissertation, Institute of Geosciences, Unicamp, 1993, 158p. 11. Castro, G.T.,França, A.S., Aranha, D.V., Borba, G.L.: “Moréia Team Work Historical, A COE Reduction from 16 to 5 US$/bpd in Three Years”, I Seminário de Reservas e Reservatorios, Rio, R.J., 9-13 setembro 1995. 12. De Wardt J P, “Operational Realities of The '90s”, World Oil V 217, No. 2, pg. 110-113, Feb. 1996. 13. Vargas, R.J.B., Coutinho, C.M.: “Campos Basin: An evaluation about 20 years of operations”, OTC 8490 Offshore Technology Conference, Houston, Texas, 5-8 may 1997. 14. Bhanu Murty, P.V.S. e Kumar, V.S.: “Cost Reduction Options for Production Operations”, II International Petroleum Conference, New Delhi, India, 1-9 dec. 1997. 15. Castro, G.T., Platenick, A.: “How to Improve The Production Using Industrial Automation”, II Seminário de Tecnologia de Produção, Salvador, Bahia, 11-14 nov. 1997. 16. Assayag, M.I., Castro, G., Minami, K.,Assayag,S.: “Campos Basin: A Real Scale Lab for Deepwater Technology Development”, OTC 8492 Offshore Technology Conference, Houston, Texas, 5-8 may 1997. 17. Khalil, C.N., et al.: “Thermochemical Process to Remove Paraffin Deposits in Subsea Production Lines”, OTC 7575 Offshore Technology Conference, Houston, Texas, 2-5 may 1994. 18. Formigli, J. and Porciuncula S.: “Campos Basin: 20 Years of Subsea and Marine Hardware Evolution”, OTC 8489 Offshore Technology Conference, Houston, Texas, 5-8 may 1997.

Figure 1 - Completion’s records evolution.

COST DISTRIBUTION

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Figure 2 - Typical distribution of the costs in production platforms.

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Figure 3 - Detailing the production platforms costs along the years.

Figure 4 – Comparison of automated platforms and the no-automated, using the index number of employees divided by the oil process capacity (the circles and squares represents all the platforms at Campos Basin in this time).

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Figure 5 - Impact on the total cost of transport (personnel, water, diesel,

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PERSONNEL'S TRANSPORT IMPACT

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Figure 6 - Personnel's transport impact on the production platform transport

cost.