Africa (Sub-Sahara) Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in.
Conformance efforts in the Cooper Basin, Australia have been focused on treatments that have the potential to increase hydrocarbon rates. This paper describes the candidate selection process and field application of two different types of conformance treatments that were designed to increase hydrocarbon rates by reducing water rates. In all cases, production of reserves was thought to be impaired by excessive water production. In the cases where water production was decreased as a result of the conformance treatment, the wells produced at significantly higher hydrocarbon rates. Descriptions of both conformance systems (a minimally-penetrating porosity-fill sealant and a hydrophobically-modified relative permeability modifier, RPM) are provided.
The process of identifying wells that have a potential for increased oil-production rates if the water rates are reduced required modification of the traditional candidate-selection criteria. This ultimately changed how the water-production mechanisms were defined. For instance, when supported by production data, channeling was still considered as a plausible water-production mechanism even if the CBL appeared to show good cement bonding to the formation and casing. In addition, RPM technology was considered viable for upwards fining reservoir sections, even if water was coning up into the well. However, special conditions also needed to apply.
In this paper, the details of how treatment candidates were selected, treatment designs, placement techniques, and results are presented. The wells and reservoirs for each case are discussed, illustrating how water production compromised the oil or gas production. The way that these details and the conformance-fluids' capabilities and characteristics were used to design the conformance treatments is also discussed.
Air injection is an Enhanced Oil Recovery (EOR) technique with limited exposure in the Asia-Pacific region and no previous application in Australia. Analogy with successful air injection projects in the USA, suggests that it could be a suitable EOR process for onshore light oil fields in Australia; no evaluation has been conducted to date.
Using open file data, high level screening criteria are used in this study to identify prospective petroleum basins, and an individual candidate reservoir is examined through a simulation study. Key issues in the application of the technique are discussed, as are directions for implementation in Australia.
Air injection involves the continuous injection of high-pressure air into the reservoir. The oxygen in the air reacts with the reservoir crude, consuming 5-10 % of the Original-Oil-In-Place (OOIP) and generating flue gases in-situ. This creates a gas drive process and acts to re-pressurize the reservoir. The process does not require water as a mobility control agent; a significant advantage in water-scarce Australia. It could also replace hydrocarbon (HC) miscible floods, freeing cleaner HC gases for energy use. Ideally the process is suited to deep, high-temperature, light oil reservoirs, and is applicable to both secondary and tertiary recovery.
The Cooper-Eromanga Basin, Carnarvon Basin (Barrow Island) and the Surat-Bowen Basin were identified as the most prospective. The simulation study conducted for ‘Reservoir A' in the Cooper Basin indicated the potential for spontaneous ignition and propagation of a stable combustion front within the reservoir; hence it is a potentially good candidate for EOR by air injection.
Given the ‘high' oil price and maturity of Australia's oil provinces, significant value is associated with EOR. Air injection is potentially suitable for Australian onshore application. The process warrants further evaluation and consideration as an alternative to accepted EOR techniques.
Typical run lives of electric submersible pumps (ESPs) in the Cooper Basin in Australia are in the range of 600 to 900 days. ESPs have been used in 15 different reservoirs in this area. When highly productive oil reservoirs were recently discovered in the Moomba area similar run lives were expected.
However, the first 12 installations in the Moomba fields only ran an average of 87 days. In 2001 a team was formed to target improved run lives. The team included production, manufacturing, engineering and management personnel from the operating company and equipment supplier.
The main problem areas identified were protector and electrical wellhead feedthru failures and power supply quality. This paper outlines the operational, engineering and equipment changes made in each of the problem areas and the resulting increase in run lives.
Failure analysis of pulled equipment demonstrated that the elastomers utilized for motor protection were being degraded. Compatibility testing of elastomers, produced fluids and injected chemicals revealed that the produced oil and water were causing the elastomers to breakdown. Although the wells were vertical, conventional labyrinth protectors could not be used because of the low gravity of the crude. The solution was to engineer a new motor protection system that was virtually elastomer free. The design utilizes metal bellows, high-density oil for gravity separation protection and high-grade o-rings. This design resulted in the first ESP motor protection system that can be used in environments with light crude that is incompatible with standard elastomers.
In addition, analysis of the power quality showed that the crude fuel utilized to power the generator sets was affecting power quality. The poor quality of the power supplied to the ESPs was potentially contributing to motor burns and wellhead penetrator failures. To improve power quality a cleaner fuel supply was sourced.
The run life improvement project is ongoing and the outcome of increased run lives is readily demonstrated.
The Moomba Field
In 1997, after 31 years of gas production, oil was discovered in the Namur and Hutton formations overlying the Moomba gas fields. To date, five oil pools have been discovered. These pools have strong aquifer support and each contain between one and five wells. Initial rates of between 3000 and 5000 barrels of low gravity (50 °API) oil per day (bopd) were typical for the wells. The primary method adopted for artificial lift was ESPs although some of the wells' productivity has declined over time requiring the installation of lower rate artificial lift systems.
The Moomba 94 pool was discovered in 1997 during the drilling of Moomba 87, a gas development well. Moomba 94 was drilled as a twin of Moomba 87 and Moomba 97 was the subsequent development well in the pool. Both wells came online at initial free flow rates of 5000 bopd. Initially both wells were completed with ESPs, with Moomba 97 later being recompleted to a jet pump due to decreased productivity.
In 1998, Moomba 95, another gas development well, also intersected oil. This oil discovery was developed by Moomba 102, a high angle development well. Moomba 102 was completed with an ESP but was also later recompleted to jet pump.
Moomba 104 exploration well, targeting oil, was drilled in 2000 and discovered the third economic oil pool in Moomba. The well tested 5000 bopd on free flow. Four further oil development wells (Moomba 118, 135, 160, 161) were subsequently drilled on this pool. Moomba 104 and 135 were completed with ESPs. The remaining wells had lower initial rates and were completed with other artificial lift methods.
The Eromanga Basin is an established Australian producing region with oil and gas found in several different Formations. At the request of an Operator, a project was undertaken to construct saturation-height functions for all the Eromanga reservoir units with a secondary objective being to define residual hydrocarbon saturations.
Initial investigations revealed many reservoirs with residual hydrocarbon columns, the significance of which had not been well understood. The residual hydrocarbons implied that imbibition, rather than drainage, capillary pressure curves were representative of water saturations in the reservoir. This insight suggested higher oil-in-place and reserves volumes than previously assumed since mobile hydrocarbons are present very close to the pressure derived Free-Water Level in imbibition systems.
When individual hydrocarbon Fields were considered, there were insufficient special core analyses to derive meaningful residual hydrocarbon or saturation-height relationships. However, on the basin scale, a significant volume of measurements had been acquired over a period of 22 years, albeit using different laboratories and a variety of measurement techniques. With knowledge of the measurement techniques and Formations sampled, the data were combined in such a way that consistent datasets were obtained for end-point relative permeabilities and drainage and imbibition capillary pressure curves.
Interpretation of these datasets produced residual oil saturation and drainage and imbibition saturation height relationships. These relations were tested against those log-derived water saturations considered most reliable by the Operator, showing excellent matches. The model developed successfully described the water saturation distributions in the reservoirs tested in a manner not previously possible. Indeed, the use of the drainage and imbibition saturation-height functions together with residual hydrocarbon relationships provides a powerful tool to determine both static and dynamic fluid contacts, while checking the validity of wireline log-based water saturations.
At the request of an Operator, a review has been undertaken of all the available Special Core Analyses (SCAL) for the Jurassic Oil reservoirs found in the Eromanga Basin of Australia. The primary objective of this study was to construct appropriate saturation-height functions for oil volume quantification and reservoir modelling. A secondary objective was the identification of residual oil saturations from suitable core analyses.
The Jurassic reservoir units involved were the Adori, Basal-Jurassic, Birkhead, Hutton, McKinlay, Murta, Namur and Westbourne Formations.
The Eromanga Basin is an established producing area, with many fields and a large database of wireline log measurements and core analyses collected over more than 20 years.
Despite a number of different Operators and a history of production in the area, the significance of the residual oil found below the pressure derived free-water levels (FWL) of many fields had not been fully recognised.
The signs that imbibition may be significant in reservoirs include:
presence of "residual oil" below the pressure derived FWL at discovery,
dry oil production from close to a FWL,
sharper log-derived transition zones than the reservoir permeability suggests.
In addition, as oil fields are produced, water sweeps through sections of reservoir. These sections have gone or are undergoing water imbibition.