New Developments in Orinoco Oil Belt Projects Reflect a Positive Effect on Reserves
Teófilo Villarroel M.
PDVSA – CVP, Puerto La Cruz, Venezuela
The Orinoco Oil Belt is located along the southern margin of the Eastern Venezuela Basin, parallel to the Orinoco River, covering a geographic area on the order of 55,000 sq km. The Belt is 600 km in length and 90 km in width. Within it lies one of the largest oil deposits in the world, roughly 1.3 trillion barrels of “oil in place". The estimated 310 billion barrels of recoverable oil match the oil reserves of Saudi Arabia. It is believed that around 90% of the extra heavy crude in the world is located in the Orinoco Oil Belt.
The area is divided, from West to East, into four distinct production zones: Boyaca, Junin, Ayacucho and Carabobo. It includes four projects in operation between the state oil company PDVSA and foreign partners: Sincor in Junin (Total-47%, Statoil-15%), Petrozuata in Junin (ConocoPhillips-50.1%), Ameriven in Ayacucho (Conoco-Phillips-40%, Chevron 30%) and Cerro Negro in Carabobo (ExxonMobil-41.6%, BP-16.6%). All four projects convert the extra-heavy 8.5° API crude to lighter sweeter synthetic crudes of 22° to 32° API at the Jose upgrading complex 200 km. to the north. These business ventures have been instituted within the last ten years with an estimated investment of more than $12 billion.
This first stage of development produces 640,000 BOPD by “cold” production methods. The extra-heavy crude is mobile in the reservoir, largely because of existing temperatures. In the extraction process a 50° API naphtha diluent is injected in the horizontal section of the producer (up to 1.5 km. long) decreasing the oil viscosity along the wellbore. The diluted crude oil is then produced, primarily employing down hole progressive cavity pumps.
A second phase, with the incorporation of Enhanced Oil Recovery Projects, is currently under development. Thermal stimulation pilot projects are being designed utilizing Steam Assisted Gravity Drainage (SAGD) and Horizontal Alternating Steam Drainage (HASD) techniques.
PDVSA – CVP has always maintained that the extra heavy oil reserve scenario in the Orinoco Oil Belt Area is very promising. This paper will help to emphasize this by presenting a compilation of positive effects that recent developments are having on the oil “in place” and reserve numbers of the joint venture projects within the area. The principal ones are outlined below:
1) – Original reserve estimates have passed the test of time.
A comparison is made between current official “oil in place” & reserve numbers (“Ministry of Energy and Petroleum”) and those submitted by the PDVSA affiliates prior to the establishment of the joint ventures. Results show that the current official numbers have increased in one of the operators and have remained equal to the early PDVSA estimates at the others. A credit to the quality of PDVSA´s early work is the fact that data from only 93 vertical wells, covering an extension of 1,800 Sq. Km., was available at that time. During the subsequent period of joint venture development a total of 1,200 horizontal producers and hundreds of stratigraphic and observation wells have been drilled by the operators. Also, numerous 3-D seismic surveys have been carried out in the area.
2) – Reserve numbers show an increase when they are recalculated using newly obtained formation water geochemical data.
The original aquifer water salinity in the Junin Area was established to be 2,300 ppm from information obtained in early vertical wells. At that time it was assumed that the formation water had the same salinity as the aquifer. Later however, subsequent horizontal producers started to cut water with anomalously high water salinity values of 15,000 ppm. At that point a multidisciplinary study was launched aiming at defining and characterizing all water sources using both vertical well tests and horizontal well water production data. Conclusions from this work show that the oil zone does indeed present high salinity values and the aquifer salinity is stable and equal to 2,300 ppm.
However, it remains a fact that the low salinity values of the aquifer were erroneously used in the petrophysical evaluation in the oil leg. Formation water saturation (Sw) values were originally calculated using the fresher water resistivity (Rw) values pertaining to the aquifer and not the more saline formation water values later obtained. The higher Sw values have thus produced lower oil saturation (So) numbers (1 – Sw = So), negatively impacting the “Original Oil in Place” figures. Preliminary calculations done by PDVSA – CVP using the newly acquired and more appropriate Rw values indicate that the Original Oil in Place (OOIP) figures will increase the current official values registered with the Petroleum Ministry.
The potential upside impact on these reserve numbers due to the recalculations associated with this new geochemical data is under current evaluation by all partners involved in the area.
3) – Reserves can be maximized with the implementation of production policies that provide correct water management practices.
The risks posed by the existing regional aquifer have proved to be less severe than what was originally believed. During this first phase of development we have learned that aquifer pressure support is lower than originally expected and that contrary to premature early assumptions the wells accumulate large volumes of extra-heavy oil after water breakthrough.
Early after initial field start up the first water breakthrough was noticed in Sincor and the water cut increased rapidly in these wells. Due to a lack of water handling capacity at that time the policy adopted was to shut in high water cut wells. Much later an increase in water handling capacity permitted putting these wells back on stream. It was then observed that during stable production periods the water cut of most wells decreased substantially and stabilized. Also, that the wells continued to accumulated large volumes of oil. Today, due to the implementation of a production policy that provides appropriate water management, production potential and reserves are being maximized.
4) – New drilling and completion techniques will have a significant positive impact on developing the huge oil resources located in “thin sands” (10 – 20 ft.) of the deltaic sequence.
Graphs of Original Oil in Place (OOIP) vs. sand thickness in the area reveal that 30 - 40% of the oil within the deltaic sequence is located in sands with a net thickness inferior to 20 ft. It is thus imperative to evaluate the most suitable way to target these thin beds which are currently not being developed.
The use of Cold Heavy Oil Production with Sand (CHOPS) techniques is a part of this initiative. This method which employs massive co-production of sand in vertical wells has been successfully applied in the Heavy Oil Belt of Canada for the past two decades. There are similarities in reservoir rock and oil properties between Canadian fields (Luseland & Lindberg) and Orinoco Belt fields which indicate that the technique should also be successful here. A CHOPS pilot project targeting the thin deltaic sequence sands will be initiated in the last quarter of this year in the Junin Area. CHOPS has never been applied in Venezuela and if successful it will be a major breakthrough in the domestic oil industry.
A second approach being proposed in reaching thin sands of limited lateral extension is the use of non-conventional “horizontal” well architectures. “U”, “snake” and “stair shape” designs are currently being analyzed. The well design will basically depend on the different possible geological scenarios with consideration being given to future workover feasibility as a principal limitation.
AAPG Search and Discovery Article #90075©2008 AAPG Hedberg Conference, Banff, Alberta, Canada