ADNOC’s full field development work in the area of sour gas injection is helping it improve recovery of oil from established fields. The work has also achieved a high level of environmental performance.
Firm oil prices, reports of constantly increasing demand and improvements in technology have made oil recovery a new focus for both national and international oil companies in the current ‘oil boom'.
Developments in this field take a considerable investment of time and funds to secure gains. However, the benefits can be significant, not just in the volume of oil recovered but also in terms of health and safety and process improvements.
With a large bank of sour reserves in its fields, the Abu Dhabi National Oil Company (ADNOC) has been working on ways to improve its hydrocarbon recovery in the onshore and offshore fields. One method it has been developing is the injection of sour gas. Lutfi Salameh, a senior reservoir engineer for ADNOC's exploration and production directorate, will deliver a paper at SOGAT on the successful development of offshore sour oil fields with applied sour/sweet gas injection in carbonate reservoirs.
Salameh and his colleagues, which include senior engineers from ADNOC and Abu Dhabi Oil Company (ADOC), have been working in the area of reservoir management, looking to find efficient techniques for prolonging and enhancing oil production and the ultimate recovery of the field life. ADNOC's interest in developing its reserves is being driven by a rising demand for gas supply to fuel development plans.
"Our sour reserves are huge, both onshore and offshore," said Salameh. "To continue producing oil at the same level we need to enhance production using gas injection. This has created an increasing demand for gas to help us enhance our oil production."
"Employing gas injection gives ADNOC the opportunity to use one of its abundant gas resources that can be produced and use it to produce more oil." The joint development project between ADNOC and ADOC has seen the first use of sour gas injection in offshore fields located in the southern part of the Persian Gulf, about 100 km west of Abu Dhabi.
The study covers an integrated full field development for two oil fields. The fields were discovered in 1982 and 1984 respectively. Oil production in the first field started in 1989 in conjunction with sweet gas injection, followed by the second field in 1995. Reservoir fluids comprise two types, one is highly under-saturated (40-43 API) with relatively low gas to oil ratio (GOR) and 6% H2S, which is reserved in Arab A reservoir. The other is a volatile oil (45-47 API) with high GOR and 18-23% H2S, which is reserved in Arab C and D upper reservoirs.
Arab A reservoir in both fields is supported by a high-pressure gas miscible drive, injecting associated gas for enhanced oil recovery. The MMP (minimum miscibility pressure) of these reservoirs is 4 250 - 4 300 psia. Slim tube tests show MMP decreases by injecting sour gas.
The fluid of Arab C and D upper reservoirs in both fields is near critical fluid. Fluid properties vary with depth, while the gas phase and oil phase coexist in the structure without significant change in their compositions. To enhance oil recovery for these reservoirs, associated gas injection by gas cycling has been applied.
"It is a field scale development," said Salameh. "As engineers we are responsible for evaluating oil and gas production performance over the long and short term, to enable management decisions. To help us do this we use advanced modelling and simulation technology, an important factor in assessing and evaluating ideas. We build compositional simulation models that match the field performance we are studying and we use it to evaluate ideas and select the techno-economic optimum plan for development. This is a long process and the modelling is an essential management tool when approving any project."
The main challenge presented by the fields was the handling of the sour gas - including its production, treatment and injection - while ensuring a safe environment.
Dealing with the necessary safety requirements makes quite a difference to the cost of the operation.
"Everything requires special materials; everything has to be specifically designed to handle the sour gas," said Salameh. "We have to use anti-corrosive material and specially trained people to avoid any problems.
Because sour gas is poisonous, if there is any kind of leak at all, it is an emergency."
The field developments also achieved a high level of environmental performance, thanks to the reduction of sour gas flaring, leaving only small pilot burner with sweet gas. This change resulted in CO2 flaring reducing from 184 million tonnes a year in 2000 to 11 million tonnes a year in 2005: SO2 flaring dropped from 90 million tonnes a year to six million tonnes a year over the same period. Production from both fields is gathered to the process facilities at the site terminal in the centre of one field. The separated gas is fully sweetened by the amine unit with 60 MMscf per day capacity. The inlet gas is with 5 mole% CO2 and 14 mole% H2S. The sweet gas (zero mole% for CO2 and H2S) is compressed to about 5 000 psig by three compressors and injected into reservoirs. The sour gas (14 mole% H2S) injection operation is currently in the process of being implemented successfully.
Currently, average oil production from the first field is 5 500 stbo/day with gas injection rate of 47 MMscf per day. Oil production from the second field is 3 500 Stbo per day with gas injection rate of 17 MMscf per day. Sour gas injection in reservoirs contributes to enhanced oil recovery and always maintains reservoir pressure.
The additional challenges and costs of dealing with the sour reserves have to be worthwhile. As a result ADNOC looks for fields where production can be assured for 25 years or more.
"We have to ensure we recover around 60% of the hydrocarbons in the reservoir, so each field is subject to four phases of development," said Salameh. "The primary depletion phase may last five years at a maximum, then pressure declines so it then needs to be enhanced. That's when we start using water injection, although we know it is harmful to the reservoir, it is also cheap. By about the 20-year mark that will no longer be effective, so water is eventually replaced with gas, which may enable us to continue production until the end of the fields' life where economic limits are reached.
"Gas injection is the optimum choice for an efficient oil displacement process. Gas is more efficient than water, which in complicated reservoirs can travel in the wrong direction, leaving oil behind. Because the gas is miscible there is no way for it to miss the oil.
"This is the first successful sour gas injection field development we've run. Now we have started applying what we have learnt to different fields, so we can develop further reserves using sour gas injection."