Overview of Cantarell field development offshore Mexico

T. Limon-Hernandez

A look at what Pemex Exploration and Production (PEP) plans for a major nitrogen injection program, facility extensions and drilling to fight production decreases in this world-class, 1-million-bopd field

Because the Cantarell complex is the most important oil field in Mexico and the sixth largest in the world, Pemex Exploration and Production (PEP) initiated a comprehensive program to increase recoverable reserves through pressure maintenance by nitrogen ([N.sub.2]) injection. This article describes the process followed to select the new development program, based on: geological, reservoir simulation and economic studies, a review of the original field development in the late 1970s and early 1980s, and the current short-term and long-term development projects. The existing production and export facilities are described, as well as existing wellhead platforms, production complexes and gas-treating facilities.

Several short-term development projects are presently being applied to debottleneck existing facilities, reduce gas flaring, and increase storage capacity and export berths using Floating Storage and Offloading vessels (FSOs). These projects are based on engineering studies and reviews of oil/gas separation and gas compression facilities.

Finally, some long-term projects were established to increase production handling capability and oil storage and exports. These projects cover a program to drill additional development wells, new wellhead platforms, new production complexes and new pipelines.


The Cantarell field complex comprises four adjacent oil fields known as Akal, Chac, Kutz and Nohoch, with Akal being the most important.[1] The complex is located in the Bay of Campeche, Gulf of Mexico, off the coast of the Yucatan Peninsula, 75 to 80 km (50 mi) NNW of Ciudad del Carmen, Fig. 1. Water depths range from 35 m in the south to 40 m in the north (115 to 131 ft). PEP is the operator of this Pemex-owned field.


Cantarell is the most important oilfield complex in Mexico, and it is the sixth largest oil field in the world, with initial oil in place of 35 billion bbl oil (Bbo) and proven/probable hydrocarbon reserves of about 13.5 Bbo equivalent. This represents about 26% of Mexico’s total oil reserves. Cantarell crude is a 19 to 22 [degrees] API Maya type.

Field production started in June 1979, reaching a peak of 1.157 MMbopd in April 1981, through 40 wells. This production level was sustained until early 1996 through the drilling of 139 development wells, using gas lift and reducing back-pressure restrictions, Fig. 2. Cantarell also produced associated gas at a rate of 430 MMscfd in 1996. And the quantity of lift gas returned by pipeline from onshore treatment for oil recovery has steadily increased.


Akal field contributes about 90% of current Cantarell oil production, and it contained more than 90% of the OOIP. Akal was discovered in 1997, and began initial production in 1979. Chac field, with less than 4% of Cantarell production, was discovered in 1976, but did not begin producing until 1991. Kutz has not yet commenced production. Nohoch, with 5% of the complex’s production, was discovered in 1978 and began production in 1979.

Oil is produced at 16 wellhead platforms. First-stage gas-oil separation is performed at some wellhead platforms and the crude is stabilized at three production complexes. Crude is transported via pipelines to three offshore tanker berths at Cayo Arcas and to storage tanks at Dos Bocas, where part of the production is exported via two offshore berths, and the balance is transported inland by pipeline. The Gulf of Mexico’s only FSO, the Ta’ Kuntah, is also moored north of the Akal-J facility to receive treated crude via a PLEM and offload to transport tankers (see OTC 10862). Produced gas is sent onshore for treatment and consumption, and the balance is returned offshore for gas lift. At least seven nearby offshore fields also share some of Cantarell’s processing and/or crude export facilities.

Regarding the field’s geology, the complex is formed by several blocks bounded by faults, Fig. 3. The structure is a large anticline oriented NW-SE; its geological configuration resulted from tectonic processes originated by the rupture and interaction of tectonic plates in the Pacific Coast. The net payzones are from the geological formations: Kimmeridgian Jurassic; Lower Cretaceous, Middle Cretaceous and the basement of the Upper Cretaceous; Paleocene-Upper Cretaceous and carbonates from the Upper Paleocene and Middle Eocene.



A well productivity decline in Cantarell was observed as reservoir pressure was falling. The initial per-well productivity of 30,000 bopd fell to 7,000 bopd, while the reservoir pressure declined to 113 kg/[cm.sup.2] from 270 kg/[cm.sup.2] (to 1,607 psi from 3,840 psi). The pressure decline is a result of fluid extraction, even with natural water influx through the south edge of the field. As a result of pressure declining to levels below the bubble point pressure, a secondary gas cap exists now in the reservoir.

Considering the remarkable reservoir pressure decline which has reduced well productivity to one-fourth of its initial value, but mostly due to the fact that water encroaching through the south flank has a lower displacement efficiency, leaving about 19% more oil trapped in the reservoir than gas expansion, a comprehensive program to maintain pressure by [N.sub.2] injection has been established, with the objective of maximizing field value.

Akal field has favorable conditions for an effective gravity drainage recovery mechanism, i.e., high permeability due to extensive fracturing, a thick reservoir section, high structural relief, and formation of a secondary gas cap. Akal also benefits from effects of gas-cap and fluid expansion, and water influx.

Akal BHP has declined to about 42% of its original value. Over recent years, this has resulted in operational problems, making it hard for PEP to sustain target oil production rates due to falling well fluid levels, increased gaslift gas needs and requirements of lower gas-lift valve settings. To increase oil production capacity and ultimate oil recovery from Akal, it is recommended that pressure maintenance be undertaken as early as practical.[2,3,4] The additional recovery under this process is estimated at more than 2 Bbo.

Pressure maintenance by water injection was discarded as an option, based on a review of a water injection project located SW of Akal, where there are some indications of substantial risk of water channeling through the fracture system, resulting in premature water breakthrough to producing wells. Based on water production data, there is a water encroachment in the southern edge of the field causing a movement of the oil-water contact (OWC). This water encroachment should be impeded to prevent the OWC moving to the northern side of the field. Pemex concluded that gas injection is the best process to accomplish this objective and the optimum long-term plan to maintain pressure in Akal.

To support this conclusion, simulation[2,3,4] and lab[5] studies were carried out, obtaining results that indicated a higher ultimate oil recovery with gas injection, compared to water injection, for pressure maintenance. Further, it is expected that gas injection will: 1) increase the beneficial effects of the gas cap, 2) diminish or avoid the negative effects of water influx, and 3) sustain well productivity.

Injection fluid selection. Once gas injection was selected as the best option to maintain reservoir pressure, the following types of gases were considered:[6] natural gas, carbon dioxide, fuel gas, air and nitrogen. For each gas, several aspects were analyzed, such as: availability, cost, project infrastructure cost, injection cost, environmental and security regulations and effects on the reservoir.

From the study, it was concluded that [N.sub.2] injection was the best option, considering a cost, on-site of $U.S. 1.1/Mcf–very low compared to natural gas cost of $2.6/Mcf. After this selection, and as a result of the contracting process for [N.sub.2] supply, the price was established at about $0.36/Mcf.

Some additional advantages of [N.sub.2] are:

* No expected contaminating effect on the reservoir

* Unlimited availability

* [N.sub.2] is inert, so no environmental damage is expected; it is not flammable or corrosive

* [N.sub.2] injection will avoid the “take away” of about 1,400 MMscfd from the gas market–if natural gas injection had been chosen–representing 31% of national gas production.

Project management. In February 1996, the Cantarell Senior Management Committee was created, with the following objectives:

* Give directions/support to establish the optimum development plan

* Guarantee exhaustive analysis of exploitation alternatives/technological options

* Further, this Committee must prove/establish an organization for planning projects in line with company orientation.

Under this Committee, an organization was formed with the objective of coordinating project planning and starting the bidding process. As the project changed from planning to mainly construction, in 1997, Executive Direction of the project was created to oversee and coordinate bids and construction supervision, and update the Master Plan/or field development, Fig. 4.


Three groups support the Executive Direction. One is related to administration and contracting new facilities construction, to elaborate/process special agreements to modify contracts and coordinate execution/control of project financial resources.

The second group, the Project Management Team, is in charge of development, administration, coordination and supervision off the construction program; evaluation of engineering and construction procedures; supervision of construction executed by contractors; and analysis and evaluation of scope changes and their impacts on the Master Plan.

The third group, Programming and Evaluation, updates/administrates the Master Plan; prepares the investment budget; coordinates actions with Cantarell Asset, the entity in charge of field operation/maintenance for field work executions; and analyzes exploitation options and evaluates their impacts on the Master Plan.

The Executive Direction has the support of one staff dedicated to the evaluation of financial and administrative processes, and another in charge of human resources and general services for the Project.

Drilling program. The Cantarell development plan considers the drilling of 205 producing wells, and eight wells for [N.sub.2] injection, to be completed in the period 1997 to 2005. To reach this goal, six platform extensions have been constructed on existing drilling platforms and 10 additional new drilling platforms are now in the construction process.

Important efforts have been made to complete wells with large-diameter tubing to increase productivity. It is estimated that 63 producing wells will be completed with 9 5/8-in. tubing, and 18 existing wells will be worked over to convert them from 7-in. to 9 5/8-in. tubing.

For drilling activity, an administrative philosophy was established to use the services of a virtually independent service unit.


Fig. 5 shows a schematic distribution of platforms and pipelines existing at the beginning of the project (1996). The production and export facilities for the Cantarell production were:

* Nine wellhead platforms without separation

* Seven wellhead platforms with first-stage separation

* One satellite production complex

* Three full-production complexes

* Two crude oil export terminals

* One pumping platform, and

* One gas compression plant.


The pipelines shown on Fig. 5 interconnect wellhead production platforms to production complex platforms and connect these to export terminals. There are pipelines connecting producing facilities from adjacent fields to Cantarell production complexes. Some heavy oil production from Ku, Maloob and Zaap fields and light oil from Ixtoc and Ek-Balam fields are exported through Cantarell facilities.

For production facilities, a design study was made in 1996 for Cantarell exploitation through a Master Plan, containing the following:

Short-term plan. The main objective is to increase production through facility upgrading already planned or under way, and debottlenecking existing facilities to maximize current infrastructure capacity and increase reliability of existing production facilities.

Systems to be debottlenecked are:

* Gathering and separation

* Crude oil collection, transportation, storage and export

* Low- and high-pressure sour gas collection and transportation

* Gas-lift gas transportation and distribution, and

* Electric power generation/distribution, and fuel gas.

Long-term plan. The main objective of this plan is to maximize the economic value of the field through a pressure maintenance program by [N.sub.2] injection. In addition to the infrastructure necessary for [N.sub.2] injection, i.e., the generation plant and pipelines, the plan includes an intensive drilling program and construction of new wellhead, production, production-complex and living quarters platforms, and pipelines according to production expectations.

The plan considers two new production complexes; each will have the following bridge-linked platforms:

* Wellhead and primary separation platform

* Gathering and riser platform

* Production platform–including integrated secondary separation, gas processing and compression, utilities and oil and gas export

* Living quarters platform, and

* Floating storage tanker.

The new production facilities will be on fixed platforms. For power generation, the concept of centralized electric power generation instead of the current gas turbine direct drive philosophy, will be examined. The new production/export systems will be integrated with existing offshore facilities for maximum utilization of existing installations and operating flexibility.

Regarding the gas-lift system, for technical/cost/safety reasons, dehydrated sweet gas is recommended for gas lift. The feasibility of using dehydrated sour gas was also studied. Offshore vs. onshore gas treatment and various pipeline distribution networks were analyzed. The recommended option is to treat all the lift gas for new wells offshore and tie the new lift-gas distribution pipelines into the existing ring to form an integrated system.

For crude export, the recommended solution incorporates a second floating storage tanker, permanently moored near the field facilities, with a relative small increase in onshore storage. The new facilities will be tied into the existing export pipelines and berth facilities for maximum flexibility. Many of the export pumps at the existing complexes will need to be upgraded to meet the new export rates. The new floating storage tanker has a capacity of about 2.2 MMb oil. A turret mooring system could allow the vessel to remain operational during storms.

Table 1 shows the expected production facilities growing under the short-and long-term plans.

Table 1. Cantarell field additional infrastructure resulting from short and long-term plans

Drilling infrastructure

Producing wells 205

Wellhead platforms 9

Platform extensions 7

Pipeline infrastructure (326 km)

Oil-gas pipelines 16

Oil pipelines 9

Gas pipelines 46

Production infrastructure

Platforms for oil stabilization 1

and export

Production platforms 2

Remote separators 19

Riser platforms 2

Monitoring and control digital system 1

Infrastructure to optimize gas usage

Compression 3

Gas treatment: 1

Integrated gas 1

Injection infrastructure

Injection wells 10

Injection platforms 1

Nitrogen plant (1,200 MMscfd) 1

Nitrogen pipeline (90 km) 1

Storage infrastructure

FSO (2.3 MMbbl) 1

Living infrastructure

Living quarters platforms 8

Contracting methodology. A new methodology with integrated contracts for Engineering, Procurement and Construction (EPC) was applied to execute investment projects. Some advantages were obtained by handling the purchase orders (POs) separate from EPCs.

Thirty-six EPC contracts and 27 POs are necessary to accomplish the Master Plan goals. The EPCs cover mainly construction of drilling, production and living quarters platforms, pipeline construction, FSO contracting and the services required to accomplish the above work. POs are directed to the purchase of equipment for platforms, such as compressors, pumps, treatment plants, separators, electrical generators, valves, etc. Up to January 1999, 31 EPCs were awarded, two are in process and three are remaining; all 27 POs are awarded, Table 2.

Table 2. Cantarell field infrastructure growth


Production complexes 3

Wellhead platforms 17

Riser platforms 1

Remote separators 8


Production complexes 5

Wellhead platforms 28

Riser platforms 1

Compression platforms 5

Integrated gas compression system 1

Gas-lift gas conditioning system 1

Injection platform 1

Remote separators 23


Nitrogen plant 1

Some of the investments for the short-term plan are handled through the Cantarell Asset, the entity in charge of the operation and field maintenance. Following are the main works included:

* Geophysical/geotechnical surveys

* Construction of platform extensions on three existing platforms

* Construction/installation of five templates with six well conductor guides each, and

* Four pipelines, which were required in a very short period.


In 1997, PEP initiated an international bid process under the form of Build, Own and Operate (BOO), to develop a private project for the supply of 1,200 MMscfd of [N.sub.2]. The plant site assigned by PEP is on the Atasta Peninsula, Campeche, Fig. 6. Under the form selected for this bid, the awarded company must construct, operate and maintain the plant and supply [N.sub.2] to the field injection site for a period of 15 years.


According to the contract signed with the Compania de Nitrogeno de Cantarell, four [N.sub.2] generation and compression modules will be constructed, starting as follows: Module 1, April 1, 2000; Module 2, July 1, 2000; Module 3, Oct. 1, 2000; and Module 4, Jan. 1,2001. Each module will have capacity to produce 300 MMscfd of [N.sub.2], compressed to 1,500 psi.

Besides these modules, the contract includes: 1) a 500-MW power plant comprising three operating gas turbine modules and one more for relays, including heat recovery to produce electricity and steam; 2) 100 km of pipelines onshore and offshore; 3) a system for seawater cooling; 4) electricity distribution; 5) a distributed control system; and 6) necessary infrastructure.

Environmental aspects were considered, following governmental regulations.

A detailed description of the plant scope and construction is presented in paper OTC 10864.


In early 1999, progress included 31 EPC contracts awarded.(7) From those, 28 are in development, two are finished and one is ready to finish; also, three EPC contracts are in planning and two are in bid process. In addition, 27 POs related to major equipment for EPC contracts have been awarded. From those, 17 have been delivered, two are ready for delivery and eight are in fabrication. All of this means a total progress of about 30%.

The successful completion of two EPC contracts allows the operation of the FSO-1 system (Ta’ Kuntah), which increases export/storage oil capacity.

The EPC related to gas handling to reduce flaring is in final construction stages and completion was expected by March 1999. The Gas Compression and Process EPC is advancing in engineering. Other important EPC contracts are those for two new production complexes which are also in the engineering phase. Debottlenecking of existing facilities is in progress, to finalize and implement gas injection and crude oil export objectives.

EPC contracts involving drilling/riser platforms are in progress, with most of the jackets and decks mechanically complete; some of these structures are already installed and others are ready for transportation. Different EPC contracts have been awarded for platform installations; such contracts provide the vessels and equipment required for that kind of task. Additionally, PEP has successfully continued the drilling program.

The [N.sub.2] injection platform is also in the engineering phase and all POs for major equipment are placed, so jacket and deck fabrication can now begin. Four EPCs are planned for the construction of living quarters platforms. Two of them are advancing in engineering and are now beginning the construction phase for three new platforms. Living quarters platform replacements on one of the existing complexes was just awarded and is in a planning phase. The last contract for living quarters platforms is in bid process.

Pipeline EPC contracts are in progress, with most of the lines designed; about 40% of them continue with construction and installation work both on- and offshore. The EPC 7, 36-in. x 86-km, high-pressure gas pipeline, Atasta-Nohoch, is nearing completion. EPC 45 is waiting on bid publication.

The [N.sub.2] supply consortium, CNC, is making progress on all critical issues and is performing the work in an acceptable manner. And finally, the project has experienced important progress in areas such as management, safety, quality assurance and environment which contribute to improving the project development.

Economics. Discussed here are some economic aspects of the Cantarell Project, such as [N.sub.2] cost, and an economic evaluation of the project, analyzing the total project and the incremental project, which considers only the investments and costs of new installations and revenues coming from oil and gas production related to those investments.(8)

Nitrogen cost. According to the contract signed with CNC, PEP will receive up to 1,200 MMscfd at the injection platform during the period from April 2000 to January 2016. [N.sub.2] cost will be defined by fixed costs based on production capacity, operation/maintenance costs, and variable costs, which will depend on fuel consumption.

[N.sub.2] unit cost will be $0.56/Mscf in the first year, and will decrease to as low as $0.23/Mscf by 2016, with an average cost for the entire period of $0.36/Mscf. Considering these figures, the following pressure maintenance operation costs, in MM$U.S., will be considered in the economic studies: Year 2000, $75.3; 2001-2012, $2,019.2; 2013-2015, $313.8; total, $2,408.3.

Economic evaluation. Two economic evaluations were made.(6) One considered the whole Cantarell Project, including Cantarell Asset; this is the total oil and gas production, the total of investments and operation and maintenance costs, and the total transportation costs. The incremental case considers only investments and costs related to the project to maximize field value through pressure maintenance, and revenues coming from oil and production attributable to this program.

Some premises were considered in the economic evaluation of these two cases, e.g.: constant oil/gas prices at 1998 levels; a 10% discount rate; a study period of 15 years; and transportation costs of $0.25/BECO for oil and $0.41/BECO for gas.

Results, before taxes, for the whole case are: internal rate of return, 954%; benefit/cost ratio, 5.4$/$; and investment recovery time, 1 year. Results, before taxes, for the incremental case are: internal rate of return, 99.5%; benefit/cost ratio, 3.6$/$; and investment recovery time, 3 years.

Conclusions. The Cantarell Project, the most ambitious and important project carded out by PEP in the last two decades, is well underway. Most work has already been awarded and is in the construction phase. Production levels have already increased 40%, and 66 new wells have been drilled. To obtain the maximum economic value from this field, an [N.sub.2] injection program, the largest in the world, was established. Facilities are already under construction and injection is expected to commence by first-quarter 2000.

Advanced technologies have been applied for project planning/evaluation. Such is the case for the simulation of reservoir/well behavior under different alternatives, surface processes and transportation processes. For Cantarell Project, all of these simulations were performed in a coordinated and timely way.

Considering the complexity and magnitude of the Pemex administrative structure, PEP established an organization for Project Management and Programming, which is acting in a dynamic way, promoting the interaction with proper entities and integration to strategies of the national oil industry. Strategies applied for construction contracting and equipment acquisition have optimized project execution, reducing the times involved in the execution phase.

Currently, some important contracts have been concluded, e.g.: 1) the FSO system, with permanent mooring and storage capacity of 2.1 MMbbl; 2) 13 wells pre-drilled on four templates; and 3) seven structure extensions constructed, on which 22 wells have been drilled. The first major compression facility completion is expected by mid-1999. And an intensive drilling program has completed 66 production wells from the project starting date up to January 1999, to meet the production goals for this period.


The authors thank Pablo Gomez, Carlos Lechuga, Rafael Munoz, Santiago Guzman and Enrique Hernandez for their contributions to the development of this article.


(1) Memoria de Labores de Pemex, 1997

(2) Netherland, Sewell and Associates, Inc., “Advisory Study,” June 1, 1996.

(3) Netherland, Sewell and Associates, Inc., “Letter Report,” July 10, 1996.

(4) Geoquest Reservoir Technologies, final report, “Cantarell field reservoir simulation.”

(5) Marathon Petroleum Latinoamerica, final report, “Analisis y pruebas especiales de petrofisica en nucleos de roca as condiciones de yacimiento.”

(6) Unigas Co., final report, “Feasibility study of gas injection in offshore Mexican oil reservoirs.”

(7) Cantarell Project monthly progress report, December 1998.

(8) Resumen ejecutivo proyecto Cantarell, Version 1998.

Dr. Thomas Limon-Hernandez, manager of programming and evaluation, Cantarell Project for Pemex Exploration and Production (PEP), graduated from the University of Mexico (UNAM) as a petroleum engineer and earned a PhD from the University of Tulsa, Oklahoma. With 32 years in the petroleum industry, he has worked with PEP since 1979. In his present position, he monitors/coordinates production system developments for the Cantarell project, and related expenditures. Prior to this, Dr. Limon managed operations and production at Cantarell, and was responsible for new technologies in workover/completion/production processes.

Gaelo de-la-Fuente, senior reservoir engineer with PEP, earned a BS in PE from the Polytechnic National Institute, Mexico. In 1967, he started work with IMP (the Mexican Petroleum Institute) as a reservoir engineer, and in 1979, assumed responsibilities in new-reservoir engineering technologies. In 1996/’97, he was operations manager in Mexpetrol Argentina, S.A., in Buenos Aires. From 1998, he has been in charge of Cantarell Project reservoir/wells engineering department.

Guillermo Garza-Ponce, process manager and coordinator fo surface/reservoir installations and development plans, Cantarell, for PEP, is a chemical engineering graduate of the Polytechnic National Institute, Mexico. He has 26 years experience in primary production in collaboration with Pemex. In early Cantarell Project stages, he coordinated planning, FSO, [N.sub.2] and upgrading work. Prior to this, he helped design installations offshore Campeche. He has worked in IMP coordinating hydrocarbon handling projects.

Maritza Monroy-Hernandez, project manager of the Cantarell Project Planning Group, with Bechtel Corp. as support for Pemex, is a chemical engineering graduate from the University of Mexico (UNAM). With 15 years experience in primary production, she started with Bechtel in IPSI, a basic engineering/technology development group, collaborating on gas-plant projects. Prior to this, she worked with IMP on primary production. She has been process manager/senior process engineer in other Pemex projects, contributing to new technologies for sweetening, dehydration and energy conservation. Ms. Monroy has made technical presentations to several venues, including the World Petroleum Conference, Norway.

Editor’s note: This article was prepared, with permission, from paper OTC 10860, “Overview of the Cantarell field development program,” presented by the authors at OTC ’99, Houston, Texas, May 4, 1999. This paper was part of a comprehensive multipaper session on Cantarell field development featuring, in addition:

* OTC 10861: Execution of EPC submarine pipeline projects in Cantarell field

* OTC 10862: Floating storage and offloading systems (FSOs) for storage and export of Maya crude oil: Concept, project execution and operation

* OTC 10863: Cantarell oilfield optimization and surface infrastructure enhancement

* OTC 10864: Nitrogen from cryogenic air separation process to be used for pressure maintenance and to enhance recovery of Cantarell complex in Campeche Bay, Mexico

* OTC 10865: Cantarell oilfield automation.

COPYRIGHT 1999 Gulf Publishing Co.

COPYRIGHT 2000 Gale Group

You May Also Like

Strong E&P growth continues

Strong E&P growth continues – Statistical Data Included The surge in drilling activity that finally got underway last year looks to grow …

Listings for pipe sizes to 5 in. OD

Tubing reference tables 2006: listings for pipe sizes to 5 in. OD World Oil’s updated tables for pipe sizes to 5-in. OD or production-tub…

ExxonMobil pulls out of Turkmenistan; signs MOU with PNG – Looking Ahead – memorandum of understanding with Papua New Guinea

ExxonMobil pulls out of Turkmenistan; signs MOU with PNG – Looking Ahead – memorandum of understanding with Papua New Guinea – Brief Article …

Control Risks Group – People in Industry – Kevin Keable appointed

Control Risks Group – People in Industry – Kevin Keable appointed – Brief Article Control Risks Group appointed Kevin Keable as business …