Sub-miscible Gas-WAG Injection Piloting and Compositional Modeling in a Carbonate Reservoir
Authors: Haajizadeh Masoud , Hafez Hafez H. , Chaliha Pradyumna Rai , Al-Katheeri Abdulla Bakheet 
Published: February 2016

The subject reservoir comprises heterogeneous carbonate formations constituting the upper zone of a giant UAE field. The reservoir is under-saturated and can be divided into lower permeability upper sub-zones and a higher permeability lower sub-zone.

Screening studies indicated that crestal gas-WAG injection would be the optimum development option because of the favorable geology. Two pilots were initiated to evaluate field performance of the WAG process: one pilot tests gas injection followed by WAG and the other tests water injection followed by WAG.

This paper covers the first pilot, including the pilot description, field observations, performance analysis, and the corresponding compositional simulations.

The pilot comprises one injector, three observers and three active producers. Initially, rich gas was injected for two years at a high rate. The rationale was to expedite data acquisition and enhance oil recovery in the vicinity of the injector, where pressure could approach the MMP. The pilot was then switched to lean gas injection for a year to recover the liquid associated with the injected rich gas. Injection rate was then reduced by 50% to minimize gas cycling and, after six months, the pilot was converted to WAG injection.

The pilot has been in operation for 4.5 years and has met all the initially-set objectives. Model predictions satisfactorily match field observations. For example, the gas, injected in upper sub-zones, quickly moves to the more permeable lower sub-zone, while the gas movement in upper sub-zones is rather gradual. Moreover, simulations accurately predict gas arrival times at observers and GOR evolution in the nearest producer. Tracer breakthrough times and GOR performance in more distant producers provide valuable information on vertical communication and lower sub-zone permeability, hence reducing key reservoir uncertainties.

Through integration of field observations and compositional simulations, this study has been instrumental in enabling reliable quantification of gas-WAG injection benefits, optimization of field-scale processes, and formulation of a robust development plan.

1. Background

Field Overview

The subject field is located in the onshore area of the UAE about 110 km to the southeast of Abu Dhabi Island. It was discovered in 1965, with production starting in 1973. The structure is an elongated, faulted, doubly-plunging anticline with the longer axis trending roughly northeast-southwest. It is about 30 km long and 10 km wide.

The main oil bearing reservoirs of the field are Units X, Y and Z, which are found at depths of about 7500 to 8000 ft. The three reservoirs are in communication through fault juxtapositions; hence, the fluid properties of the three reservoirs are similar. The oil is relatively light with an API gravity of about 40°, a solution gas-oil ratio of ~770 scf/stb, a bubble point pressure of ~2100 psig, and a formation volume factor of ~1.62 rb/stb. The original reservoir pressure was around 3900 psi @ 7600 ft TVDSS.

Unit X contains about 20% of the total oil originally in place (OIP). The reservoir is heterogeneous and highly stratified, and is made up of four sub-zones. Figure 1 presents a schematic cross-section across the reservoirs, illustrating the porosity and permeability variations and the stratification. Figure 2 presents average properties for various sub-zones along with typical petrophysical logs. Sub-zones XIU, XIL and XII are at the top with a horizontal permeability ranging from 1 to 10 mD. The better developed sub-zone XIII is located at the base of the reservoir with an average horizontal permeability reaching ~50 mD and contains about 15% of the Unit X OIP.

The Unit X reservoir is currently not on production, except for the ongoing pilot activities. It was put on production in 1990 but after about 5 years, production from the reservoir was stopped. The reason was that the pressure could not be maintained adequately via partial through-fault communication with the more prolific underlying reservoir, which is under peripheral water injection [1].