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REACTIVATION OF MATURE FIELDS IN NORTHERN MEXICO.

Authors: Ing. Antonio Narváez, PEMEX Exploration and Production

Dr. Luis Roca Ramisa, Schlumberger Oilfield Services

Copyright 2005, CIPM. Este artículo fue preparado para su presentación en el cuarto E-Exitep 2005, del 20 al 23 de febrero de 2005 en Veracruz, Ver., México. El material presentado no refleja necesariamente la opinión del CIPM, su mesa directiva o sus colegiados. El artículo fue seleccionado por un comité técnico con base en un resumen. El contenido total no ha sido revisado por el comité editorial del CIPM.

RESUMEN

Los campos maduros y/o marginales en México se definen como aquellos que el margen de utilidad, aunque rentable; no son suficientemente competitivos con otros proyectos de PEMEX Exploración y Producción. El concepto de madurez y/o marginalidad es dinámico; es decir, puede ser temporal en función de las condiciones de mercado y nivel de costos de extracción y producción. En los EUA, se considera como maduro y/o marginal, aquellos campos de aceite con producciones inferiores a 10 bpd por pozo (IOGCC).

En el Activo Integral Poza Rica-Altamira existen más de 12 campos de aceite que son considerados como maduros y/o marginales; sin embargo, y poseen todavía una cantidad considerable de reservas 2P y tienen factores de recobro históricos promedio relativamente bajos (>5%). Estos campos fueron descubiertos a lo largo de la década de 1990 y tienen actualmente producciones que oscilan entre 3 y 55 bpd por pozo. Con un enfoque adecuado, estos campos pueden ser reactivados económicamente y ser un detonante para el re-surgimiento de la Región Norte como productora neta de aceite.

En este trabajo se presentan los retos y planes diseñados por la Región Norte para la re-activación de estos campos, así como también las experiencias con campos maduros y/o marginales en otras partes del mundo.

ABSTRACT

Although profitable, Mexico's marginal fields are those whose profitability is not competitive with other PEMEX Exploration and Production projects. The concept of marginality is dynamic in that it is a function of market conditions and lifting and production costs. Mature fields could be also marginal, but the term is applied strictly to those

fields that have passed their peak production. Fields producing less than 10 bbl/d are considered marginal In the U.S. (IOGCC).

There are 12 oilfields considered marginal or mature in the Poza Rica-Altamira asset in Mexico's North Region. Nevertheless, these fields still have considerable 2P reserves, but their average historical recovery factors are relatively low (< 5%). These fields production started in the early 1990s. Today, production from these fields averages between 3 and 55 bbl/d. These fields could be reactivated economically and therefore serve as a springboard for Mexico's North Region to again become a net oil producer with comprehensive study, properly applied technology and a shift in the use of human resources.

This paper discusses the challenges of reactivating the North Region and presents plans for doing so. Experiences with marginal or mature fields in other locations are cited as a backdrop for this study.

INTRODUCTION

The main driver of the oil industry continues to be the demand for oil and gas, which is expected to grow at a cumulative rate of 1.8% from 2001 through 2025 (Fig. 1).2 Despite the projected growth in demand, production in the world's remaining proven reserves has peaked in many areas and will peak in others within the next 10 years.

Fig. 1. World energy demand.

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Remaining reserves are in a limited number of countries. With the exception of the harsh deepwater environments, future new exploration and growth will happen mainly in the Eastern Hemisphere. Figure 2 illustrates the peak discoveries in different areas around the globe.

Fig. 2. Oil reserves distribution.

The larger bubbles, representing remaining oil reserves in MMbbl, appear mainly in Eastern Hemisphere countries.

Peak production in remaining reserves will peak in the next 10 years, which means the E&P industry will become more production based over time. This scenario points to the importance of increasing production in marginal fields and prolonging it in mature fields where economically feasible. Although new discoveries, new technologies and new evaluations will come into play, the overall scenario will not change significantly. In Mexico, where oil production is a key element of the country's continued economic growth, production from marginal and mature fields will play an important part in its future fiscal well-being.

Twelve oilfields in Mexico's North Region—the Poza Rica-Altamira asset—are considered marginal or mature. The term marginal, which can be applied to any oilfield, is dynamic in that it is a function of market conditions and lifting and

production costs. Mature fields are marginal, and are further distinguished by the fact that they have already passed their peak production. These 12 oilfields, which were put on production in the early 1990s, were unprofitable until 1996. After that time, gas profitability has remained good to excellent, but profitability from the production of oil, which peaked in 1996, has been significantly less impressive (Fig. 3).3

Fig. 3. North region's profit per business type.

Today, average production from the Poza Rica asset is 70 bbl/d; it is 40 bbl/d from the Altamira asset. Overall production from the North Region is 100 bbl/d. These intermittent wells also produce a high percentage of water. Despite the declining trend in production, Poza Rica-Altamira reserves have significant remaining value, with 2P reserves at 5531 MBOE for the Poza Rica and 4881 MBOE for Altamira. In general, several difficulties must be overcome for these fields to be profitable: decreasing production, high production costs, excess personnel and a low level of financial investment.

Several scenarios could be considered with regard to administering these mature and marginal fields. These fields could be closed, but such a move would demand huge financial resources and would mean the loss of any profit. Therefore, closing the

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12 fields in the Poza Rica-Altamira asset is not practicable. Reactivating these fields could significantly reduce operations costs and therefore improve profitability. This would appear to be the best option, yet challenges remain. First, human resources are the variable with the greatest impact on cost. The scope and focus of the workforce in this area would have to be shifted to economically support a reactivation scenario. Second, a substantial improvement in performance would require a step-change in how decisions are made with regard to these fields. Third, reactivating these fields will require the application of fit-for-purpose, cost-effective technology that will increase ultimate recovery through extended field life.

NORTH REGION BUSINESS FRAMEWORK

In 2003, North Region 3P reserves represented 43% of the PEMEX Exploration and Production total 3P reserves. Despite this high percentage, income from this region accounted for only 8% of the income from total PEMEX wells in operation. Investments made in the North Region to date totaled $2 billion USD, or 27% of the PEMEX total, and North Region workers accounted for 27% of the total PEMEX Exploration and Production workforce. The disparity in these numbers points to the need to make significant changes in how and where workers are distributed, and in how critical it will be that future investments are highly targeted to meet specific production and income levels. In addition, an unfavorable fiscal regime in Mexico further necessitates that production in the mature Poza Rica-Altamira be carried out in the most efficient manner possible—in a way that ensures future profitability.

In the Poza Rica-Altamira asset, support staff makes up a higher percentage of the workforce than do well operations staff. A significant share— 42%—of the total 3170 workers are used in maintenance in the Poza Rica; in the Altamira, 34% of the total 1992 workers are working at the administrative level. In each case, essential areas related to well operations are being covered by only about 40% of the total workforce. This imbalance must be remedied in coming years with

a focused strategy for efficiently allocating human resources. In other words, labor as a variable factor must be brought into alignment with production.

While more fields are becoming marginal (26% in 2004, up from 11% in 1996), investment and production have dropped along with increased costs, volatile prices and lower profits. These areas must be balanced in order for reactivation of the North Region fields to be a step in the right direction.

NORTH REGION GEOLOGICAL CHARACTERISTICS

The geology of Mexico's North Region— specifically, the Ébano-Pánuco area—serves as an example of the type of geology encountered in similar mature fields such as the Poza Rica-Altamira. Heavy oil production in the Ébano-Pánuco comes from fractures in the Cretaceous San Felipe and Agua Nueva formations. The reservoir rock is a Cretaceous carbonate composed principally of fine-grained limestone with varying amounts of detrital shale. Four lithotypes are volumetrically dominant: argillaceous lime mudstone (shaly limestone), detrital shale (calcareous shale), chalk (clean, fine-grained limestone) and Argillaceous mudstone.4

These lithotypes change vertically with stratigraphic position and laterally with geographic location. In general, the rocks become more shaly toward the west.

Core samples taken in the Ébano-Pánuco reveal low but measurable values of porosity, ranging from 0.4 to 18%. In more than 60% of the thin sections, the pores are too small to be seen with a petrographic microscope (micropores). Because of this small pore size, the overall matrix porosity and permeability are relatively low to low. Lithotypes in the San Felipe and Agua Nueva formations have lower values of porosity (3.75 to 7.5%) and permeability (0.008 to 0.0a mD) due to the presence of detrital shale mixed with micrite grains.

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Water saturation is uniformly high in the most shaly rocks because the throats of the matrix pores are very small. The irreducible water saturation is very low (15%) in the porous and permeable chalk intervals.

Fracture porosity is very important in the area because of the low total volume of matrix porosity. Virtually all the fractures in the rocks are of tectonic origin, and at least two stages have occurred in the rocks, both producing vertical fractures. The vertical seal is provided by the Mendez and overlying Tertiary formations. Log evaluations have shown that the Mendez contains a significant quantity of shale. The basal part of the Mendez formation contains a higher proportion of limestone than the upper part, and it is likely that some locations in the lower Mendez contain fractures that may act as a Type 1 reservoir.

Oil gravity in the Ébano-Pánuco ranges from 11 to 14 API, with viscosities ranging from 1200 to 8000 cp. This area has produced approximately 1 billion barrels of oil from several different sectors. Some wells in the area still produce by natural flow, but water production is a major problem in these reservoirs where water has coned upward through the natural fractures.

STRATEGIES AND PLANS FOR REACTIVATION

Obviously, the objective of boosting reactivation in the North Region is to significantly increase production. Opportunities abound for PEMEX Exploration and Production to ensure that mature North Region fields become net producers. Exploration in geologic basins associated with these fields must be carried out to identify additional areas that are ripe for development. Appraisal of these fields would include seismic studies and identifying strategic wells that are candidates for reentry. Development of mature fields could include directional drilling, where appropriate. Fields and wells would be optimized by artificial lift systems and water control measures. Secondary and tertiary recovery would also be considered.

A focused and ongoing human resources strategy will be a key part of profitable reactivation to ensure that labor as a variable factor directly relates to production. Without such a strategy, costs might reach $35 per barrel in 10 years as Poza Rica-Altamira production declines. Key elements of this strategy would include:

• relocating employees to more productive areas

• modifying work shifts and improving labor relations

• transferring jobs to expanding business units, inside or outside PEMEX Exploration and Production

• establishing incentives for performance linked to increased production and lowered costs.

Targets for linking the size and processes of technical and administrative staff support areas to operations will have to be reset to levels that are more in line with production. Currently, 65% of staff works in support areas in the Poza Rica-Altamira. Reducing that number to 30% would reduce costs significantly. To fill in the gaps resulting from this reduction, training should be offered to improve personnel skills in design, drilling and operations of wells and installations. State-of-the-art information technology and telecommunications equipment should be put in place to reduce the time personnel currently spend in managing data and transmissions. Where possible, maintenance, personnel, accounting and other support areas can be relocated within PEMEX or outsourced to move resources to areas more essential to reactivation activities.

Along with a human resources strategy, the operation and management of wells should be expanded and automated where appropriate. Since these activities require substantial manual labor, energy and maintenance, steps must be taken to optimize management activities. Capacities for separation, storage, pumping, transport, injection and compression must be gradually resized, and controls can be implemented to measure and handle fluids

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automatically and remotely. Crude oil pumping activities can be streamlined to take advantage of the large storage and pumping capacity already available in the Poza Rica-Altamira.

Funding is another area where projects in mature fields are at risk. Without revising the fiscal regime and the Law of Financing and Public Expenditure, there are options for strengthening the sourcing for financing mature fields. First, reasonable and appropriate baselines—particularly for costs— should be established for evaluating projects. Second, assistance can also be gained by designating multiannual financial resources for mature fields, without restricting these funds to present technical limitations. Third, arrangements could be made with the federal government to permit PEMEX to use financial reserves for reactivating those fields with the most oil and gas reserves. Finally, peer groups (competing among equals for financial contracts) could establish the financial budget as is done by other E&P operating companies.

PUTTING ADVANCED TECHNOLOGY TO WORK

Overall, Mexico's oil industry must come to rely on technology that lowers lifting costs so that marginal, mature fields become viable. Making use of and developing new fit-for-purpose, cost-effective technology and services is essential to retarding the decline in performance of the world's production base, while concurrently increasing ultimate recovery through extended field life. In addition, digital technologies must become more central to providing an infrastructure that maximizes the value of specialists and their knowledge to improve the overall efficiency of reactivating mature fields.

Currently, there are a number of ways where using appropriate technologies can add significant value to mature fields. Production and reservoir management tools can more accurately describe and control production for long-term economic benefit. For instance, mutiphase flow metering Vx* technology allows the simultaneous measurement

of oil, gas and water flow without fluids separation, which typically requires bulky separator equipment. The Wet Gas module of Vx permits measurement of condensates, an important capability where both oil and gas wells are produced or where the production character changes over time. In general, production metering lowers overall costs by providing quick, efficient well tests and early water detection.5

Cost-effective well construction is another area where specific technologies can help lower overall well/field construction costs and access greater reserves per well. In the Burgos basin, for example, the Drillers Technology Corporation (DTC) uses its telescopic double rigs to improve drilling efficiency. The performance record set the bar for drilling in the Poza Rica-Altamira. For example, the average drilling time was 10.68 days, with the best time at 9.09 days (drilling times adjusted to total well depth of 2000 mV). Best average ROP in an 8 1/2-in. hole section was 31.3 m/hr; in a 6 1/8-in. hole section the average was 22.9 m/hr. Nonproductive time (NPT) was reduced from 14.63% to 2.88% between drilling the first and second wells. With lessons learned in the Burgos basin, similar achievements can be expected with DTC rigs in the Poza Rica-Altamira to lower drilling time and costs.

Fig. 4. Schematic diagram of a DTC telescopic double rig.

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New techniques for reentry, stimulation and intelligent completions can ensure that the value of mature fields be fully realized. In the past, reentries have often been hampered by small hole sizes. A new technique, called TTRD*, or Thru Tubing Rotary Drilling, combines small high-torque motors, reliable high signal strength MWD and sophisticated multicurve resistivity systems. TTRD technology has demonstrated that sidetracks of up to 25,500 ft can be drilled at good penetration rates to targets once considered uneconomical. This technology also provides the ability to "daisy chain" targets, a capability that will surely forestall the decommissioning of existing infrastructure until the reservoir is totally drained.

With the Rapid* service provided by some technical companies, wells can quickly be identified as candidates for stimulation. This time savings translates into reduced rig time and costs. Once these wells are identified, a fiber-based fluid fracturing technique has been shown to fully distribute within the fracture. This full-height packing of the fracture effectively increases the surface area open to flow. The difference in well productivity can be considerable.

Intelligent completions, such as those applying one-trip ESP completions and creating a large zonal pressure and flow differential, will mean that fewer wells must be drilled. They also allow for better pressure management, reduced water production and improved recovery rates.

Other cutting-edge, reliable and proven technologies have been used in Mexico's Chicontepec basin. These innovative technologies have set the standard for improved production and cost management, and may demonstrate the efficacy of their application in Mexico's mature fields in the near future. Among these technologies are

• Axia-Production Management—A fit-for-purpose downhole pumping system with improved reliability and simplified field operations, and the Axia lifting service that delivers real-time pump data via a web browser to monitor well operations.

Fig. 5. Axia* fit-for-purpose integrated lifting system.

• Well trajectory planning with 4D seismic— A new seismic technology that acquires data digitally, avoiding the signal averaging applied in conventional seismic, for much quicker processing that can more accurately plan the well track to avoid water contact and improve production.

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Fig. 6. Well trajectory planning with 4D seismic.

Fig. 7. Deep reading measurements.

• Deep reading measurements—A new cross-well resistivity that measures resistivity across thousands of feet to provide a "view" of often missed reservoir features such as bypassed oil and water fingering, and to proactively manage and produce reservoirs and infill drilling programs; when combined with controlled source electromagnetic and magnetotelluric surveys, yields a resistivity map of the reservoir.

• ABC* Analysis Behind Casing—Provides a full range of openhole-quality measurements in wells after they are cased to reveal the effects of production on reservoirs, such as water encroachment and depletion, where rig efficiency is of critical importance to the economic success of a mature field drilling program.

Fig. 8. ABC* Analysis Behind Casing.

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• Well construction for mature fields— Services that can link multiple small accumulations with a single wellbore by reducing the number of wells/slots, and that can access small single targets, resulting in reduced well costs, accurate well placement, increased step-out capability, and higher steering capability.

Fig. 9. Drilling in complex reservoirs require excellent steering capabilities.

FloScan Imager*—Deploys sensors across the wellbore to measure holdups and velocities at any point in the well to provide a flow profile and an understanding of exactly which zones in the well are producing and what they are producing.

EXPERIENCES WITH MATURE FIELDS

Mature fields in Mexico's North Region will ultimately benefit from lessons learned in mature fields in other parts of the world that have had successful reactivation programs. Important technologies have been applied with considerable success in these key areas:

• Effective processes to quickly identify wells that are candidates for production enhancement

• Logging techniques that assist in building the complete petrophysical picture of hydrocarbon zones behind casing in existing wells

• Accurate well placement to ensure long- term production

• Efficient well construction that maximizes drilling performance, improves penetration rates, avoids existing slot/well preparation, and reduces hole size and drilled length— all to improve the economics of well reactivation.

A scenario parallel to the Poza Rica-Altamira exists in the Chicontepec fields within the North Region. In its first year of reactivation activities, this field is on track toward increased production and profitability. This field has the largest 3P hydrocarbon reserves in Mexico—18,129 MMBOE. Within one year of applying a reactivation program to this field, 25 km of roads have been built, 12 platforms set, 81 wells drilled with 58 completed, 55 km of pipeline laid, and a 3.3-km pumping network installed.

To reactivate the Chicontepec fields, a new approach was taken that called for

• Appraisal of fields with seismic activities to identify strategic wells for reentry

• Development of fields via directional hole • Optimization of fields and producing wells

using artificial lift systems and water control

• Secondary and tertiary recovery schemes. Fig. 10. FloScan Imager* (FSI) System.

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Overall, average oil production currently stands at 50 bbl/d per well. Over the next 25 years, 13,372 wells will be drilled with an expected oil production between 600 and 700 bbl/d and gas production exceeding 700 MMft3/d.

CURRENT ACTIVITIES TOWARD REACTIVATION OF THE POZA RICA-ALTAMIRA

Success in the Chicontepec has paved the way for new activity in the Poza Rica-Altamira, and much has already been done to begin a successful reactivation of this asset. To date, a multidisciplinary team has been formed to look at all aspects of the project. The marginal fields have been ranked in terms of the status of their development, optimization of artificial lift systems and the production infrastructure. Companies having experience in marginal fields have been consulted, along with consultants in specialized areas from academia and other corporate institutions. A financing plan has been put together, along with payment arrangements. Better labor relations have already been initiated.

The team has also set forth a list of services that would optimally be contracted outside PEMEX Exploration and Production. Among these are converting wells to optimized artificial lift systems; reengineering of production installations; negotiating permits for rights of way; workovers; handling produced water; administration and maintenance of installations and the infrastructure of production, just to name a few.

CONCLUSION: FINDINGS AND CHALLENGES AHEAD FOR POZA RICA-ALTAMIRA

The Poza Rica-Altamira, like other mature fields, faces great challenges due to high production costs, excess personnel, low levels of financial investment and decreasing production. Despite these challenges, mature fields have important reserves, installations, opportunities, experience and personnel skills. In addition, geologic basins associated with mature fields have good remaining

potential for development that could greatly affect overall outcome.

A successful strategy going forward will include pinpointing those reservoirs with remaining potential that can produce with a margin over the cost to extract. Once identified, they must be managed in such a way that they are no longer losing value. The application of fit-for-purpose technology, reallocation of human resources to take greatest advantage of personnel talents, and allocating financial resources to cover the special needs of these fields will be required to increase and prolong production from these important North Region assets.

ACKNOWLEDGEMENTS

The authors wish to thank PEMEX and Schlumberger for the permission and support to publish this paper.

REFERENCES

1. Marginal Oil and Gas: Fuel for Economic Growth, IOGCC, 2003.

2. BP Statistical Review of World Energy, June 2004.

3. Antonio Narváez Ramirez, 2004 "Management of Mature and Marginal Fields: The Chicontepec Success," presented at the SPE Mature Fields Forum, Denver, Colorado

4. Caracterización de Yacimientos, Área Ébano- Pánuco, Veracruz, México, reporte interno de PEMEX Exploración y Producción, 1998.

5. Burgos Review, Schlumberger Publication, 2002.

6. Satish Pai, "Lifting Our Game: Technology in a Mature Fields Environment," 2004 presented at AAPG, Cancun, Mexico.

Note: An asterisk throughout this document denotes a mark of Schlumberger.