From play to production: the Cooper unconventional story—20 years in the making

2015 ◽  
Vol 55 (2) ◽  
pp. 407 ◽  
Author(s):  
Carl Greenstreet
Keyword(s):  
East Coast ◽  
Market Access ◽  
Horizontal Wells ◽  
Gas Flows ◽  
Resource Potential ◽  
Unconventional Resources ◽  
Gas Shales ◽  
Reservoir Conditions ◽  
Structural Closure ◽  
Cooper Basin

The Cooper Basin is Australia’s leading onshore producing hydrocarbon province, having produced more than 6 Tcf of natural gas since 1969. The basin is undergoing renewal 45 years later, driven by the emerging growth of east coast LNG export-driven demand. Following North America’s shale gas revolution, the Cooper Basin’s unconventional potential is now widely appreciated and it is believed to hold more than 100 Tcf of recoverable gas. This resource potential is held in four stacked target unconventional lithotypes, each having demonstrated gas flows: tight sands—heterogeneous stacked fluvial sands; deep coal—porous dry coals, oversaturated with gas; shales—thick, regionally extensive lacustrine shales; and, hybrid shales—mixed lithotype containing interbedded tight sandstones, shales and coals. Industry activity initially focused on the Nappamerri Trough, where more than 25 contemporary exploration wells have been drilled, proving up an extensive basin-centred gas play with >1,000 m of continuous overpressured gas saturated section outside of structural closure. Santos has had a team focused on unconventional resources for nearly 20 years and successful results have been quickly tied into the producing infrastructure. This has been demonstrated with the Moomba–191 REM shale success, Moomba–194 and the recent Moomba–193H connection, one of the basin’s first fracture-stimulated horizontal wells. Prospective geology, existing infrastructure and market access makes the Cooper Basin well positioned for unconventional success. Each resource play is unique and commercial success requires considered adaptation of established technologies and workflows, based on a understanding of local geological and reservoir conditions. Commercialisation activity now seeks to define play fairways, characterise and prioritise reservoir targets and determine appropriate drilling and completion approaches.

The Nappamerri Trough, Cooper Basin unconventional plays: proving a hypothesis

2012 ◽  
Vol 52 (2) ◽  
pp. 662 ◽  
Author(s):  
Carrie Trembath ◽  
Lindsay Elliott ◽  
Mark Pitkin
Keyword(s):  
Shale Gas ◽  
Gas Flow ◽  
Primary Source ◽  
Gas Flows ◽  
Gas System ◽  
Central Trough ◽  
The Usa ◽  
Early Exploration ◽  
Structural Closure ◽  
Cooper Basin

Beach Energy has started exploring unconventional gas in the Nappamerri Trough, the central trough within the Cooper Basin, where the Permian section has long been regarded as the primary source for most of the conventional hydrocarbons found within the basin. This extended abstract discusses the data used to identify the unconventional play and the exploration program carried out to date. Mud weights, drill stem test (DST) pressures and log data from early exploration wells identified the Permian formations as overpressured. This with geochemical and mineralogy analyses indicated that the Roseneath and Murteree Shales had potential similar to successful shale gas plays being developed in the USA. The quartz and siderite content within both shale sections indicated sufficient brittleness for successful fracture stimulation. In addition, the Nappamerri Trough Permian section showed low permeabilities, which, when combined with overpressure, suggested a basin-centred style play within the Epsilon and Patchawarra sandstones and possibly the Toolachee Formation sandstones. During 2010–11, Beach drilled two exploration wells sited outside structural closure to test both the shale gas and basin centred gas system. Both wells have now been fracture stimulated, with very encouraging gas flows from the Roseneath to Patchawarra section. The latest geological data confirms the pre-drill potential for both gas flow from the shales and the presence and production of gas from sandstones outside structural closure, resulting in a significant shale and tight gas resource booking. Ongoing exploration and development will target a potential 300 Tcf gas in place in PEL 218.

Co-Current and Countercurrent Migration of Gas Kicks in “Horizontal” Wells

1999 ◽  
Vol 121 (2) ◽  
pp. 96-101 ◽  
Author(s):  
H. Baca ◽  
J. Smith ◽  
A. T. Bourgoyne ◽  
D. E. Nikitopoulos
Keyword(s):  
Test Section ◽  
Gas Flow ◽  
Gas Injection ◽  
Horizontal Wells ◽  
Gas Flows ◽  
Countercurrent Flow ◽  
Drilling Operations ◽  
Operating Window ◽  
Annular Pipes ◽  
Injection Rates

Results from experiments conducted in downward liquid-gas flows in inclined, eccentric annular pipes, with water and air as the working fluids, are presented. The gas was injected in the middle of the test section length. The operating window, in terms of liquid and gas superficial velocities, within which countercurrent gas flow occurs at two low-dip angles, has been determined experimentally. The countercurrent flow observed was in the slug regime, while the co-current one was stratified. Countercurrent flow fraction and void fraction measurements were carried out at various liquid superficial velocities and gas injection rates and correlated to visual observations through a full-scale transparent test section. Our results indicate that countercurrent flow can be easily generated at small downward dip angles, within the practical range of liquid superficial velocity for drilling operations. Such flow is also favored by low gas injection rates.

Australian onshore petroleum acreage release 2016

2016 ◽  
Vol 56 (1) ◽  
pp. 495
Author(s):  
Justin Gorton
Keyword(s):  
Coastal Waters ◽  
Petroleum Industry ◽  
Petroleum Exploration ◽  
Resource Potential ◽  
Gas Industry ◽  
Unconventional Resources ◽  
Australian State ◽  
Global Demand ◽  
Future Policy ◽  
Significant Opportunity

This paper compiles material from state and territory jurisdictions describing the location and resource potential of Australian onshore and coastal waters acreage to be made available for petroleum exploration in 2016. The Australian state and territory governments continue to support investment in the petroleum industry through the annual provision of land for exploration, which is promoted nationally and internationally. Technical assessments are provided with the release, which detail the potential for conventional and/or unconventional resources. The level of assessment will depend on exploration maturity, but may include a description of the geological setting, review of exploration history, summary of key results, and subsurface maps/sections. In addition to this, any updates on recent upstream developments and government initiatives, as well as present and future policy directions that relate to onshore petroleum exploration, may be described, particularly for jurisdictions that are not making land available this year. With global demand for gas—led by Asia—expected to grow at 2.6% annually between 2015 and 2025, investing in Australia’s petroleum and gas industry presents a significant opportunity to supply into this growing market.

Unconventional hydrocarbons in shales: source rock or waste zones?

2015 ◽  
Vol 55 (2) ◽  
pp. 474
Author(s):  
Nachiketa Mishra ◽  
John Kaldi ◽  
Ulrike Schacht
Keyword(s):  
Organic Compounds ◽  
Hydrocarbon Generation ◽  
Bakken Formation ◽  
Unconventional Resources ◽  
Hydrocarbon Content ◽  
Basin Scale ◽  
Unconventional Hydrocarbons ◽  
Mercury Injection Capillary Pressure ◽  
Continuous Source ◽  
Cooper Basin

This extended abstract summarises the objectives of a research project that will provide insight into hydrocarbon generation and accumulation in continuous-source reservoirs and how to best exploit such unconventional resources in Australia, specifically in the Cooper Basin. It compares and contrasts a productive shale from the US—the Bakken Formation—with shales from the Cooper Basin. Unconventional resources, such as the Devonian-Mississippian Bakken Formation, have been assumed to be continuous source-reservoirs where the oil is generated from organic-rich shales with minimal migration. It is possible, however, that the shale intervals are a waste zone (a leaked seal). These waste zones form when the buoyancy pressure of the hydrocarbon exceeds the capillary forces in the seal, resulting in tertiary migration. Oil saturation values strongly correlate with the hydrocarbon content parameter (S1/TOC) from Rock-Eval. Values of 120 mgHC/gC are typically indicative of non-indigenous or migrated hydrocarbons (reservoirs or leaked seals). Mercury injection capillary pressure (MICP) analysis of core samples can also diagnose whether a shale is a source or a seal. Organic shales with high capillary entry pressures generally have low hydrocarbon content, in line with in-situ generation; shales with low entry pressures have comparatively higher hydrocarbon content and indicate migration from an underlying accumulation. Once these waste zones are identified on a basin-scale, specific samples from the Bakken Formation will be analysed using micro-scale sealed vessel pyrolysis, combined with monitoring of the biomarkers and other organic compounds using mass spectrometry. As the composition of organic compounds is altered during migration, this will confirm whether they are generated locally or migrated.

NEW GAS DISCOVERIES IN THE NORTHERN COOPER BASIN

1996 ◽  
Vol 36 (1) ◽  
pp. 104
Author(s):  
H.R.B. Wecker ◽  
V. Ziolkowski ◽  
G.D. Powis
Keyword(s):  
Seismic Survey ◽  
Gas Flows ◽  
Mount Isa ◽  
Seismic Acquisition ◽  
Reservoir Sandstones ◽  
Well Data ◽  
Gas Potential ◽  
Southeast Queensland ◽  
Cooper Basin

Over the last two decades, minimal gas exploration was undertaken in the northeastern Cooper Basin. It was viewed the area held negligible gas potential due to the perceived absence of conventional anticlinal traps and the marginal reservoir quality of the Permian sandstones.With the award of permit ATP 549P to Mount Isa Mines Limited in mid-1993, available seismic and well data were reviewed to highlight potential fault-controlled traps in the region and to define areas likely to contain more favourable reservoir sandstones. A vibroseis seismic survey provided the initial prospects and leads inventory upon which the 1994 drilling program was based. Four prospects were tested resulting in three gas discoveries.Based on these encouraging results, an additional phase of seismic acquisition was completed to increase the prospect inventory. Thereafter, a five well program was undertaken. Whilst the two appraisal wells were successful, three wildcat wells failed due to ineffective trapping.A completion and testing program has been initiated to further evaluate the field discoveries.From an exploration viewpoint, the recognition of a consistently productive sandstone in the basal Toolachee Formation within a broad fairway across the eastern ATP 549P permit block was a significant result which has important implications for future activities. Within the fairway, gas flows varying from 0.4 MMcfd up to 6.0 MMcfd were measured on openhole tests. In addition, substantial gas volumes in low permeability sandstones within the Patchawarra Formation have been defined.These discoveries, coupled with the number of prospects and leads and the proposed gas pipeline to Mount Isa and to southeast Queensland markets, provide strong impetus to the continued evaluation of this northern extension of the Cooper Basin gas province.

SANDSTONE RESERVOIR GEOMETRY OF NON-MARINE SEDIMENTS IN THE TOOLACHEE GAS FIELD

1977 ◽  
Vol 17 (1) ◽  
pp. 50
Author(s):  
S. Bevan Devine ◽  
Colin G. Gatehouse
Keyword(s):  
Gas Field ◽  
Cross Sectional ◽  
Field Extensions ◽  
Trapping Mechanism ◽  
Reservoir Geometry ◽  
Structural Closure ◽  
Basin Boundaries ◽  
Field Area ◽  
Reserve Estimates ◽  
Cooper Basin

The concept of Genetic Increments of Strata (GIS) has been applied to correlations of the non-marine rocks of the Early Permian Patchawarra Formation of the Cooper Basin. Boundaries of GIS in the non-marine rocks are related to a dynamic model of non-marine deposition in which discrete sandstone bodies result from channel activity.In the 9 wells in the Toolachee Gas Field area of about 150 sq. miles, log correlations based on these principles determined eight major sandstone bodies, six of which hold gas reserves. The sandstone bodies are elongate and sinuous. They have cross-sectional dimensions of about 5 miles wide by up to 60 ft thick. Faulting and differential compaction have influenced the locations of the axes of the channel sandstone bodies.The value of mapping the geometry of the channel sandstones in the Cooper Basin lies in establishing a possible trapping mechanism which is independent of structural closure and which requires only a structural dip nonperpendicular to the channel sandstone direction; and providing a geologic basis for gas reserve estimates, the positioning of future appraisal and development wells and the prediction of field extensions and nearby new fields.An estimate of the proven-probable gas in place in the Toolachee Gas Field (560 BCF) based on the channel sandstone mapping is comparable with estimates based on lumping all pay intervals together in each well and drawing geometric pay isoliths. Estimates of possible reserves are increased by the mapping because of the introduction of the trapping mechanism of sandstone margins. The Toolachee Field has the potential to be perhaps doubled in size.

Cooper Basin source rock atlas

2016 ◽  
Vol 56 (2) ◽  
pp. 594
Author(s):  
Lisa Hall ◽  
Tehani Palu ◽  
Chris Boreham ◽  
Dianne Edwards ◽  
Tony Hill ◽  
...  
Keyword(s):  
Spatial Distribution ◽  
Source Rock ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Predictive Tool ◽  
Resource Potential ◽  
Petroleum Systems ◽  
Petroleum Resource ◽  
Hydrocarbon Yield ◽  
Cooper Basin

The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin. The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals. The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.

Fieldwide Application of Autonomous Inflow Control Valve in Increasing the Field Recovery in One of the Matured Fields in the Sultanate of Oman: Case Study

2021 ◽  
Author(s):  
Salim Buwauqi ◽  
Ali Al Jumah ◽  
Abdulhameed Shabini ◽  
Ameera Harrasi ◽  
Tejas Kalyani ◽  
...  
Keyword(s):  
Control Valve ◽  
Oil Production ◽  
Horizontal Wells ◽  
High Water ◽  
Lessons Learned ◽  
Water Production ◽  
Sultanate Of Oman ◽  
Well Performance ◽  
Reservoir Conditions ◽  
Water Cut

Abstract One of the largest operators in the Sultanate of Oman discovered a clastic reservoir field in 1980 and put it on production in 1985. The field produces viscous oil, ranging from 200 - 2000+ cP at reservoir conditions. Over 75% of the wells drilled are horizontal wells and the field is one of the largest producers in the Sultanate of Oman. The field challenges include strong aquifer, high permeability zones/faults and large fluid mobility contrast have resulted that most of the wells started with very high-water cuts. The current field water cut is over 94%. This paper details operator's meticulous journey in qualification, field trials followed by field-wide implementation and performance evaluation of Autonomous Inflow Control Valve (AICV) technology in reducing water production and increasing oil production significantly. AICV can precisely identify the fluid flowing through it and shutting-off the high water or gas saturated zones autonomously while stimulating oil production from healthy oil-saturated zones. Like other AICDs (Autonomous Inflow Control Device) AICV can differentiate the fluid flowing through it via fluid properties such as viscosity and density at reservoir conditions. However, AICVs performance is superior due to its advanced design based on Hagen-Poiseuille and Bernoulli's principles. This paper describes an AICV completion design workflow involving a multi-disciplinary team as well as some of the field evaluation criteria to evaluate AICV well performance in the existing and in the new wells. The operator has completed several dozens of production wells with AICV technology in the field since 2018-19. Based on the field performance review, it has shown the benefit of accelerating oil production as well as reduction of unwanted water which not only reduces the OPEX of these wells but at the same time enormous positive impact on the environment. Many AICV wells started with just 25-40 % water cut and are still producing with low water cut and higher oil production. Based on the initial field-wide assessment, it is also envisaged that AICV wells will assist in achieving higher field recovery. Also, AICV helped in mitigating the facility constraints of handling produced water which will allow the operator continued to drill in-fill horizontal wells. Finally, the paper also discusses in detail the long-term performance results of some of the wells and their impact on cumulative field recovery as well as lessons learned to further optimise the well performance. The technology has a profound impact on improved sweep efficiency and as well plays an instrumental role in reducing the carbon footprint by reducing the significant water production at the surface. It is concluded that AICV technology has extended the field and wells life and proved to be the most cost-effective field-proven technology for the water shut-off application.

Nonideal Isentropic Gas Flow Through Converging-Diverging Nozzles

1990 ◽  
Vol 112 (4) ◽  
pp. 455-460 ◽  
Author(s):  
W. Bober ◽  
W. L. Chow
Keyword(s):  
Mach Number ◽  
Gas Flow ◽  
Accurate Solution ◽  
Gas Flows ◽  
Kutta Method ◽  
Runge Kutta Method ◽  
Nonideal Gas ◽  
Reservoir Conditions ◽  
Flow Through ◽  
Isentropic Gas

A method for treating nonideal gas flows through converging-diverging nozzles is described. The method incorporates the Redlich-Kwong equation of state. The Runge-Kutta method is used to obtain a solution. Numerical results were obtained for methane gas. Typical plots of pressure, temperature, and area ratios as functions of Mach number are given. From the plots, it can be seen that there exists a range of reservoir conditions that require the gas to be treated as nonideal if an accurate solution is to be obtained.

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