The Cliff Head is one of the most significant discoveries in the offshore Northern Perth Basin. Hence, understanding the structure and geology of the field is essential to further evaluate the offshore region in the basin. Two structural models were developed with the objective to achieve a better understanding of this field. The first model is focused on the Permian and older strata, while the second model is for the overburden. In addition, reservoir properties models (e.g. porosity model and water saturation model) were developed to better understand the reservoir facies and hydrocarbon distribution. Examination of the structural models has shown that there are two main sets of faults within the Cliff Head area, which can be categorized into the following: the deep Permian faults that are truncated against the Late Permian unconformity, and younger Cretaceous faults that were developed during the Early Cretaceous rifting. It has also shown that the oil accumulation within the field is structurally trapped within Permian aged set of horsts and is mainly reservoired within the Irwin River Coal Measures. The secondary target (e.g. the underlying High Cliff Sandstone) is mostly beneath the regional oil-water contact of −1257.8 m TVDss, except in the highest structural point in the field, where Cliff Head-6 was drilled. The Irwin River Coal Measures in the study area contained four high resolution depositional sequences that displayed a finingupward pattern as depicted by the Gamma Ray log response and are interpreted to have mainly deposited in a fluvial depositional system. The High Cliff Sandstone, in contrast, contained two high resolution depositional sequences that displayed a coarsening upward sequences as supported by Gamma Ray log response and were interpreted to have mainly deposited in marginal marine settings. Reservoir properties modeling was also conducted utilizing the 3D models, where a 3D porosity model was calculated and shows that the Irwin River Coal Measures, in general, exhibit higher porosity distribution than the underlying High Cliff Sandstone, even though the later has coarser and more laterally extensive sand sheets. This is probably attributed to diagenetic porosity reduction within the High Cliff Sandstone caused by the formation waters. The calculated 3D water saturation model also confirms the presence of a single regional oil-water contact within the field and hence, reservoir heterogeneities and fault seal capacities did not affect the hydrocarbon distribution within the field. Finally, all the calculated models (e.g. lithofacies model, porosity model, and water saturation model) were integrated to estimate the recoverable hydrocarbons in place, where the Cliff Head is estimated to contain a total of 15.2 million barrels.
Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.
Haghighi, M (The University of Adelaide) | O'Reilly, DI (Chevron Australia Pty Ltd, The University of Adelaide) | Hunt, AJ (Chevron Australia Pty Ltd) | Sze, ES (Chevron Australia Pty Ltd) | Hopcroft, BS (Chevron Australia Pty Ltd) | Goff, BH (Chevron Australia Pty Ltd)
This paper demonstrates how good technical evaluations and focused operational application can enhance the value of a mature asset. The Windalia reservoir underlies Barrow Island (BWI), situated 56 km from the coast of Western Australia, and has produced oil since 1965. Waterflooding commenced shortly after initial production, in 1967, and remains the main drive mechanism in the field today. Throughout the life of this onshore field, water injection and oil production have varied according to asset strategy and economic conditions. In this case study, we share how recent improvements made in the areas of Reservoir Surveillance and Operations activities have increased water injection efficiency and total oil recovery.
Through the use of new methods and workflows, the BWI Sub-Surface team was able to target specific areas of the field to distribute water to in order to increase injection and maximise oil production. For example, new workflows were built with the real-time PI monitoring system to analyse Pressure Fall Off (PFO) tests from each of the 147 waterflood patterns in detail. Capacitance-Resistance-Modeling was also leveraged to guide individual well target injection-rates. Operationally, several projects were also initiated to increase water injection into the right areas of the field.
The new Reservoir Management approach has significantly increased the volume of water being injected into the areas of need, supporting improved levels of oil production. For the first time in almost 10 years, the stream-day water injection rate has exceeded 90,000 bwipd. The results from PFO transient interpretation and pattern balancing proved effective in directing water to low-pressure, high-GOR areas of the field. They also provided valuable information about formation perm-thickness and skin. The phenomenon of water-cycling was also largely avoided, owing to close monitoring of production well tests and water injector transient surveys.
The present work addresses reservoir and operational aspects of Australia's largest active waterflood. The lessons shared are highly applicable to a low oil price environment, as they show how fit-for-purpose and low-cost acquisition of reservoir data can lead to improved field performance.
Electrical Submersible Pump (ESP) lift is extensively used in offshore production systems. Although real-time pump operating parameters and the production data are commonly available according to the recently developed digital energy technologies, the analysis of the acquired data is still insufficient to monitor, diagnose, interpret, and analyze reservoir performance, wellbore integrity, and ESP operating status and efficiency in a real-time manner. Further, the traditional ammeter card diagnosis cannot identify leakage of tubing, underperforming pump lifting, and low pump working efficiency.
This paper summarizes typical characteristics of different downhole malfunctions in ESP wells, provides a novel approach to detect those problems systematically and automatically. The developed management system incorporates real-time ESP current data and interpret ammeter card by neural network analysis, which has been trained through over 900 wells. We also derived the analytical solutions for wellhead pressure buildup analysis as a supplement to neural network analysis. Consequently, this model is able to detect downhole problems that cannot be identified by ammeter card. This diagnosis model also sets thresholds for key parameters, and alarm operation team through satellite in a timely manner. This model is a reliable supplementary to the traditional ammeter card diagnosis method, and the online utility provides complement flexibility to cooperate with field operations in real-time. The early-stage identification and resolution of ESP problems can lead to a great cost-saving and less maintenance requirements owing to this intelligent system. This workflow has been successful in field trials.
Over the past decade the Airborne Gravity Gradiometer (AGG) has been applied to a range of hydrocarbon exploration plays in settings from Australia to the Americas. Case study examples will illustrate that fixed-wing and helicopter borne AGG, when combined with high-resolution magnetics and available 2D seismic profiles, provide the means to rapidly, efficiently and safely explore for a variety of hydrocarbon exploration plays, including basement structural traps, salt structures and carbonate reefs.
The AGG technology
The Airborne Gravity Gradiometer (AGG) was designed and built explicitly for airborne use by the FALCON project (van Leeuwen, 2000) and called the FALCON AGG. Since 2005, this technology has used fully digital electronics. The digital AGG is smaller and lighter than other gravity gradiometers, permitting its installation in smaller aircraft, particularly helicopters.
Improved airborne gravity data quality
AGG provides twenty times better spatial resolution [150m versus 3,000m], and five times less noise [0.15 mGal versus 1.0 mGal] than conventional Airborne Gravity (Dransfield and Christensen, 2013). With the advent of a helicopter borne system AGG surveys can now be conducted as draped surveys in rugged terrain and at lower flight speed than by fixed wing aircraft, translating into additional improvement in the lateral resolution of the AGG data [45m].
Rapid AGG data acquisition
The AGG system has been designed specifically for use in light aircraft and demonstrates minimum sensitivity to air turbulence. The system can operate in turbulent conditions and routinely acquires in excess of 4,000 line-km per week. This translates into very rapid data acquisition, when contrasted to ground-based gravity acquisition. Fernandez et al. (2010) published an AGG case study from Argentina, Figure 1. A ground gravity survey of similar resolution (300m by 150m gravity station spacing) would require ~70,000 ground gravity station, or nearly two years of ground crew field work. In contrast the AGG survey was completed in two months with no safety incidents.
Rachapudi, R. V. (Kuwait Oil Company) | Haider, B. Y. (Kuwait Oil Company) | Al-Mutairi, T. (Kuwait Oil Company) | Al Deyain, K. W. (Kuwait Oil Company) | Al-Yahya, M. (Kuwait Oil Company) | Shakeel, A. (Kuwait oil company) | Qureshey, K. R. (Kuwait Oil Company) | Harith, M. (Schlumberger)
Continuous well performance monitoring plays a key role in making decision related to well workover and production optimization. Well parameters and corresponding rates over a period of time will represent the change in well performance. Live Well models are useful for estimating the continuous well production rates. Well models become live if they get updated with changing fluid and reservoir properties along with proper calibration to latest well conditions.
In general industry practice is to update the model manually; this is a tidious and time consuming process. Umm Gudair Field Development team implemented a real time system using available resources that integrates and runs workflows between corporate data base, well surveillance data base and well models. Workflows were implemented as part of the real time system to calculate the well parameters from sensor readings and update the models to run on daily basis, such that the models become live and production rates will be estimated.
The daily output generated from the workflows is basically updated well models and parameters along with production estimation report that will get emailed to users. The daily report contains the information about well status, potential, reasons for well closure etc. The workflows are intelligent enough to flag the need for model calibration and surface rate measurements. The daily estimated well parameters will be saved back to database for visualization. In conclusion, real time system was implemented to keep the well models live and useful as a tool for optimizing the oil production, improving the ESP's run life and delaying the well intervention requirements.
Several hundred of Intelligent wells well that combine downhole flow control and monitoring have been installed over the last decade in a wide range of reservoir production scenarios. Numerous publications have reported the successful use of the technology to reduce the number of well interventions, improve sweep efficiency, reduce risk, mitigate production problems, etc. A number of zonal inflow and outflow control methodologies have been proposed to meet a wide range of different well objectives as well as different production or injection conditions. Research still continues in the areas of simple reactive or predefined passive control methods employed by Intelligent wells. This is even more true if it is planned to use proactive control which requires optimisation of a complex multivariable problem.
Efficient downhole flow control comes at the cost of adding an additional pressure loss. Such losses can be significant, jeopardizing the well productivity and sometimes carrying the risk of a reduced well performance of the intelligent well when compared to the corresponding conventional well. Installing artificial lift can compensate for this reduced well performance; not only extending the well life, but also adding additional well control flexibility. However, it also poses two extra problems: how to (a) optimally design the artificial lift equipment and (b) avoid interference between the I-well's control of the zonal inflow and control of the artificial lift.
This paper sets out how to(1) Add control flexibility to downhole flow control by artificial lift and (2) Design an electric submersible pump that operates flexibly with down hole, multi-zone inflow control actions.
Improved active and passive downhole flow control will be discussed in a rigorous, mathematical manner that allows the conclusion that the combination of artificial lift and downhole flow control provides greater zonal flow control flexibility and reduces the inflow imbalance. Also, two conceptual, electric submersible pump design options, employing (1) a variable wellhead choke and (2) a variable pump operating frequency, are proposed and illustrated. Both of these proposed pump design options could cope with the changing well inflow performance created by downhole flow control devices in situations where the standard pump design workflow was ineffective.
Liu, Keyu (CSIRO Earth Science and Resource Engineering) | Clennell, Michael Benedict (CSIRO Earth Science and Resource Engineering) | Honari, Abdolvahab (University of Western Australia) | Sayem, Taschfeen (University of Western Australia) | Rashid, Abdul (CSIRO Earth Science and Resource Engineering) | Wei, Xiaofang (Research Institute of Petroleum Exploration and Development, PetroChina) | Saeedi, Ali (Curtin University)
A series of laboratory investigation on factors affecting Enhanced Oil and Gas Recovery and CO2 geo-sequestration were conducted. The coreflooding experiments were done using a relatively heavy crude oil (18° API), a number of brines of 0.18%-2.5% NaCl and varieties of cores with a range porosity and permeability from 15% and 17 mD to 19% and 330 mD under some typical reservoir pressure-temperature condition of 1164-3300 psi and 50-83 °C. Factors affecting CO2 enhanced oil and gas recovery including the effects of the petrophysical properties of the reservoir rocks, formation water salinity, reservoir pressure, the Minimum Miscibility Pressure (MMP), total volume (PV) injected and injection rate and gravity segregation.
Excellent recovery factors in the range of 27%-34% Original Oil In Place (OOIP) and almost 100% gas recovery were achieved through immiscible and miscible CO2 flooding. Some of the coreflooding experiments were monitored with a medical CT in real time. The coreflooding experiments have shown that (1) reservoir petrophysical properties with permeability difference of up to an order of magnitude do not affect the CO2 EOR factor; (2) variable EOR can be achieved both at reservoir pressures below or above the CO2-oil MMP; (3) Incremental oil recovery is proportional to the pore volume (PV) of CO2 injected up to 3PV; (4) No significant additional recovery was observed beyond the MMP; (5) CO2-Water alternating gas (WAG) flooding can be quite effective in EOR in terms of the less amount of CO2 injected as compared to that for the single CO2-water flooding to achieve the same EOR; (6) there is no benefit to use low-salinity CO2 WAG flooding; (7) the optimum injection rate in the laboratory is around 1 cc/minute. These finding may provide some useful insight and guide for the field application of CO2 enhanced oil and gas recovery; (8) During enhanced gas recovery using supercritical CO2, gravity segregation may occur in some porous-permeable reservoir with denser supercritical CO2 preferentially enter through the bottom of the reservoir.
Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible pumps in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains approximately 1.3 billion barrels of STOIIP in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately 40% of the oil production is from the ESP oil wells.
To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields.
The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 100 deviated producers. ESP was selected as the artificial lift mode for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift mode for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 11 horizontal producers are on ESP lift and the remaining three wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities.
The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and SRB. 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field.