MASSIVE HYDRAULIC FRACTURE STIMULATION OF EARLY PERMIAN GAS RESERVOIRS, BIG LAKE FIELD, COOPER BASIN

1984 ◽  
Vol 24 (1) ◽  
pp. 180
Author(s):  
D. J. Stanley ◽  
G. Halliday
Keyword(s):  
Hydraulic Fracture ◽  
Joint Venture ◽  
Oil And Gas ◽  
Gas Production ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Potential Resource ◽  
Primary Porosity ◽  
Initial Results ◽  
Cooper Basin

In 1981, South Australian Oil and Gas Corporation Pty Ltd commenced a project to apply Massive Hydraulic Fracture (MHF) technology to the tight gas reservoirs of the Tirrawarra and Patchawarra Formations of the Big Lake Field. Four wells had defined the potential at depths of 8500-10 000 ft (2500-3000 m) in the early 1970s but early attempts to stimulate gas production were unsuccessful.The Tirrawarra Sandstone, as a massive unit of 120-200 ft (35-60 m) thickness, was a prime candidate. The Patchawarra sandstones, ranging up to 40 ft (12 m) thick and interbedded with shales and coals, presented a more difficult problem.Petrologic analysis disclosed quartz sandstones in which the pore system consists mainly of large irregularly shaped dissolution pores. Diagenesis has destroyed primary porosity and precipitated authigenic illite, illite-smectite, kaolinite and siderite. The gas contains 32 per cent CO2 and is very dry. Temperatures are close to 400°F (200°C). The formations are overpressured.The project has drilled two wells, Big Lake 26 and 27, and applied two MHF treatments in Big Lake 26. One further MHF remains to be done in Big Lake 27. Each MHF treatment has been tailored to the particular petrologic, reservoir, stratigraphic, pressure and temperature conditions of that zone. The tailoring of MHF design has been further refined by running a 'mini-frac' with 10 000 gal (45 000 L) of fluid. MHF designs have involved up to 620 000 lb (280 000 kg) of sand, 60 000 lb (27 000 kg) of sintered bauxite and 300 000 gal (1350 kL) of gel. Having management on-site to react to aberrations and vary the design has been important in operations.One Tlrrawarra Sandstone MHF has been unsuccessful (as predicted) and the other, on initial results, appears highly successful. The Patchawarra Formation MHF speared off into a coal but appears moderately successful. Long-term flow tests will provide definitive results.Encouraged by these initial results, the Joint Venture Partners have drilled two further wells in the Big Lake Field which await MHF treatment. The gas-in-place is estimated at about 1.5 trillion cubic feet (42.5 billion cubic metres). Three other tight gas prospects of similar size, Burley, McLeod and Kirby, have been identified. The size of this potential resource provides a strong incentive to attempt to make MHF treatments economically viable in the Cooper Basin.

Hydraulic fractures productivity performance in tight gas sands—a numerical simulation approach

2011 ◽  
Vol 51 (1) ◽  
pp. 519
Author(s):  
Jakov Ostojic ◽  
Reza Rezaee ◽  
Hassan Bahrami
Keyword(s):  
Hydraulic Fracture ◽  
Effective Field ◽  
Gas Production ◽  
Simulation Software ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Gas Recovery ◽  
Single Well ◽  
The Impact

The increasing global demand for energy along with the reduction in conventional gas reserves has lead to the increasing demand and exploration of unconventional gas sources. Hydraulically-fractured tight gas reservoirs are one of the most common unconventional sources being produced today and look to be a regular source of gas in the future. Hydraulic fracture orientation and spacing are important factors in effective field drainage and gas recovery. This paper presents a 3D single well hydraulically fractured tight gas model created using commercial simulation software, which will be used to simulate gas production and synthetically generate welltest data. The hydraulic fractures will be simulated with varying sizes and different numbers of fractures intersecting the wellbore. The focus of the simulation runs will be on the effect of hydraulic fracture size and spacing on well productivity performance. The results obtained from the welltest simulations will be plotted and used to understand the impact on reservoir response under the different hydraulic fracturing scenarios. The outputs of the models can also be used to relate welltest response to the efficiency of hydraulic fractures and, therefore, productivity performance.

PETROLEUM AND HOT DRY ROCK: TWO TYPES OF ENERGY SHARING COMMONALITIES

1998 ◽  
Vol 38 (1) ◽  
pp. 830 ◽  
Author(s):  
S.P. Narayan ◽  
D. Naseby ◽  
Z. Yang ◽  
S.S. Rahman
Keyword(s):  
Fracture Mechanics ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Geothermal Energy ◽  
Petroleum Industry ◽  
Gas Production ◽  
Tight Gas ◽  
Mode Fracture ◽  
Hot Dry Rock ◽  
Cooper Basin

The Cooper Basin is the largest gas-producing basin in Australia and hosts a huge volume of natural gas in low permeability (known as 'tight gas') sandstone formations. Hydraulic fracture treatments, based on 'opening mode' fracture mechanics, are routinely carried out to unlock tight gas and to accelerate its recovery. Information regarding insitu stresses and natural fractures is required for successful fracture treatments. However, hydraulic fracturing is still often problematic, in part due to the relatively high insitu stresses and temperatures in the region. A vast amount of Hot Dry Rock (HDR) geothermal energy resources exists in granites below the sedimentary rocks in the Cooper Basin. Exploitation of HDR requires the same drilling and completion technologies as used in the petroleum industry. Hydraulic fracturing is also necessary for HDR reservoir creation, and requires characterisation of insitu stresses and natural fractures, as does tight gas production. It has been realised that the mechanism for reservoir stimulation in granitic rocks is proppant free shear dilation that is related to 'sliding mode' fracture mechanics. Furthermore, seismic imaging of hydraulic fracture propagation is well established in the HDR industry. These two technologies, developed in HDR, may have potential application to the petroleum industry for tight gas production. The geographic proximity of tight gas and HDR geothermal energy in the Cooper Basin and common exploitation technologies should justify close collaboration between the petroleum industry and HDR researchers.

No Need for Radio Active Tracer When Mother Nature Helps Detecting the Effective Hydraulic Fracture Height

2022 ◽  
Author(s):  
Rinat Lukmanov ◽  
Said Jabri ◽  
Ehab Ibrahim
Keyword(s):  
Hydraulic Fracture ◽  
Natural Radioactivity ◽  
Gamma Ray ◽  
Fracture Propagation ◽  
Radioactive Isotopes ◽  
Main Element ◽  
Tight Gas ◽  
Well Test ◽  
Gas Reservoirs ◽  
Fracture Height

Abstract The tight gas reservoirs of Haima Supergroup provide the majority of gas production in the Sultanate of Oman. The paper discusses a possibility of using the anomalies from natural radioactivity to evaluate the fracture height for complex tight gas in mature fields of Oman. The standard industry practice is adding radioactive isotopes to the proppant. Spectral Gamma Ray log is used to determine near wellbore traced proppant placement. Spectral Noise log in combination with Production logs helps to identify the active fractures contributing to production. These methods complement each other, but they are obviously associated with costs. Hence, majority of wells are fracced without tracers or any other fracture height diagnostics. However, in several brown fields, an alternative approach to identify fracture height has been developed which provides fit-for-purpose results. It is based on the analysis of naturally occurring radioactive minerals (NORM) precipitation. The anomalies were observed in the many gas reservoirs even in cases when tracers were not used. At certain conditions, these anomalies can be used to characterize fracture propagation and optimize future wells hydraulic Fracture design. A high number of PLTs and well test information were analyzed. Since tight formations normally don't produce without fracturing, radioactive anomalies flag the contributing intervals and hence fracture propagation. The main element of analysis procedure is related to that fact that if no tracers applied, the discrepancy between normalized Open Hole Gamma Ray and Gamma Ray taken during PLT after 6-12 months of production can be used instead to establish fracture height. This method cannot be applied for immediate interpretation of fracture propagation because time is required to precipitate NORM and using the anomalies concept. The advantage of this method is that it can be used in some fields to estimate the frac effectiveness of wells without artificial tracers. It is normally assumed that the Natural radioactivity anomalies appear mainly due to co-production of the formation water. However, in the fields of interest the anomalies appear in wells producing only gas and condensate. This observation provides an opportunity for active fracture height determination at minimum cost.

scholarly journals Unconventional Gas Production from Hydraulically Fractured Well-An Application of Direct Search Based Optimization Algorithm

2019 ◽  
Vol 8 (2S11) ◽  
pp. 2726-2737
Keyword(s):  
Objective Function ◽  
Fracture Propagation ◽  
Gas Production ◽  
Production Model ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Unconventional Gas ◽  
Fracture Geometry ◽  
Propagation Behavior ◽  
Fractured Well

Unconventional gas reservoirs are now the targets for meeting the demand for gas. These reservoirs are at the depth of more than 10,000 ft (even over 15000 depth as well) and are difficult to be exploited by conventional methods. For the last decades hydraulic fracturing has become the tool to develop these resources. Mathematical models (2D and pseudo-3D) have been developed for fracture geometry, which should be realistically created at the depth by surface controllable treatment parameters. If the reservoir rock is sandstone, then proppant fracturing is suitable and if the rock is carbonates, then acid fracturing is applicable. In both cases, proper design of controllable treatment parameters within constraints is essential. This needs proper optimization model which gives real controllable parametric vales. The model needs the most important analyses from geomechanical study and linear elastic fracture mechanics of rock containing unconventional gas so that fracture geometry makes maximum contact with the reservoirs for maximum recovery. Currently available software may lack proper optimization scheme containing geomechanical stress model, fracture geometry, natural fracture interactions, real field constraints and proper reservoir engineering model of unconventional gas resources, that is, production model from hydraulically fractured well (vertical and horizontal). An optimization algorithm has been developed to integrate all the modules, as mentioned above, controllable parameters, field constraints and production model with an objective function of maximum production (with or without minimization of treatment cost). Optimization is basically developed based on Direct Search Genetic and Polytope algorithm, which can handle dual objective function, non-differentiable equations, discontinuity and non-linearity. A dual objective function will meet operator’s economic requirements and investigate conflict between two objectives. The integrated model can be applied to a vertical or horizontal well in tight gas or ultra-tight shale gas deeper than over 10,000 ft. A simulation (with industrial simulators) was conducted to investigate and analyse fracture propagation behavior, under varying parameters with respect to the fracture design process, for tight gas reservoirs. Results indicate that hydraulic fracture propagation behavior is not uninhibited in deep reservoirs as some may believe that minor variations of variables such as in-situ stress, fluid properties etc. are often detrimental to fracture propagation in some conditions. Application of this model to a hypothetical tight and ultra-tight unconventional gas formations indicates a significant gas production at lower treatment cost; whereas the resources do not flow without any stimulation (hydraulic fracturing).

Technology Focus: Unconventional and Tight Reservoirs (July 2021)

2021 ◽  
Vol 73 (07) ◽  
pp. 57-57
Author(s):  
Leonard Kalfayan
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Alternative Methods ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Liquid Loading ◽  
Well Production ◽  
Tight Carbonate ◽  
Water Blocking ◽  
Tight Reservoirs

As unconventional oil and gas fields mature, operators and service providers are looking toward, and collaborating on, creative and alternative methods for enhancing production from existing wells, especially in the absence of, or at least the reduction of, new well activity. While oil and gas price environments remain uncertain, recent price-improvement trends are supporting greater field testing and implementation of innovative applications, albeit with caution and with cost savings in mind. Not only is cost-effectiveness a requirement, but cost-reducing applications and solutions can be, too. Of particular interest are applications addressing challenging well-production needs such as reducing or eliminating liquid loading in gas wells; restimulating existing, underperforming wells, including as an alternative to new well drilling and completion; and remediating water blocking and condensate buildup, both of which can impair production from gas wells severely. The three papers featured this month represent a variety of applications relevant to these particular well-production needs. The first paper presents a technology and method for liquid removal to improve gas production and reserves recovery in unconventional, liquid-rich reservoirs using subsurface wet-gas compression. Liquid loading, a recurring issue downhole, can severely reduce gas production and be costly to remediate repeatedly, which can be required. This paper discusses the full technology application process and the supportive results of the first field trial conducted in an unconventional shale gas well. The second paper discusses the application of the fishbone stimulation system and technique in a tight carbonate oil-bearing formation. Fishbone stimulation has been around for several years now, but its best applications and potential have not necessarily been fully understood in the well-stimulation community. This paper summarizes a successful pilot application resulting in a multifold increase in oil-production rate and walks the reader through the details of the pilot candidate selection, completion design, operational challenges, and lessons learned. The third paper introduces and proposes a chemical treatment to alleviate phase trapping in tight carbonate gas reservoirs. Phase trapping can be in the form of water blocking or increasing condensate buildup from near the wellbore and extending deeper into the formation over time. Both can reduce relative permeability to gas severely. Water blocks can be a one-time occurrence from drilling, completion, workover, or stimulation operations and can often be treated effectively with solvent plus proper additive solutions. Similar treatments for condensate banking in gas wells, however, can provide only temporary alleviation, if they are even effective. This paper proposes a technique for longer-term remediation of phase trapping in tight carbonate gas reservoirs using a unique, slowly reactive fluid system. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200345 - Insights Into Field Application of Enhanced-Oil-Recovery Techniques From Modeling of Tight Reservoirs With Complex High-Density Fracture Network by Geng Niu, CGG, et al. SPE 201413 - Diagnostic Fracture Injection Test Analysis and Simulation: A Utica Shale Field Study by Jeffery Hildebrand, The University of Texas at Austin, et al.

THE DEVELOPMENT OF THE TIRRAWARRA OIL AND GAS FIELD

1984 ◽  
Vol 24 (1) ◽  
pp. 278
Author(s):  
H. T. Pecanek ◽  
I. M. Paton
Keyword(s):  
Carbon Dioxide ◽  
Oil And Gas ◽  
Gas Injection ◽  
Oil Field ◽  
Oil Reservoir ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Associated Gas ◽  
Oil And Gas Field ◽  
Cooper Basin

The Tirrawarra Oil and Gas Field, discovered in 1970 in the South Australian portion of the Cooper Basin, is the largest onshore Permian oil field in Australia. Development began in 1981 as part of the $1400 million Cooper Basin Liquids ProjectThe field is contained within a broad anticline bisected by a north-south sealing normal fault. This fault divides the Tirrawarra oil reservoir into the Western and Main oil fields. Thirty-four wells have been drilled, intersecting ten Patchawarra Formation sandstone gas reservoirs and the Tirrawarra Sandstone oil reservoir. Development drilling discovered three further sandstone gas reservoirs in the Toolachee Formation.The development plan was based on a seven-spot pattern to allow for enhanced oil recovery by miscible gas drive. The target rates were 5400 barrels of oil (860 kilolitres) per day with 13 million ft3 (0.37 million m3) per day of associated gas and 70 million ft3 (2 million m') per day of wet, non-associated gas. Evaluation of early production tests showed rapid decline. The 100 ft (30 m) thick, low-permeability Tirrawarra oil reservoir was interpreted as an ideal reservoir for fracture treatment and as a result all oil wells have been successfully stimulated, with significant improvement in well production rates.The oil is highly volatile but miscibility with carbon dioxide has been proven possible by laboratory tests, even though the reservoir temperature is 285°F (140°C). Pilot gas injection will assess the feasibility of a larger-scale field-wide pressure maintenance scheme using miscible gas. Riot gas injection wells will use Tirrawarra Field Patchawarra Formation separator gas to defer higher infrastructure costs associated with the alternative option of piping carbon dioxide from Moomba, the nearest source.

Some challenges in hydraulic fracturing of tight gas reservoirs: an experimental study

2011 ◽  
Vol 51 (1) ◽  
pp. 499 ◽  
Author(s):  
Vamegh Rasouli ◽  
Mohammad Sarmadivaleh ◽  
Amin Nabipour
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Interaction Mechanism ◽  
Natural Fracture ◽  
Gas Reservoirs ◽  
Tight Sandstone ◽  
True Triaxial ◽  
Rock Types ◽  
Interface Parameters

Hydraulic fracturing is a technique used to enhance production from low quality oil and gas reservoirs. This approach is the key technique specifically in developing unconventional reservoirs, such as tight formations and shale gas. During its propagation, the hydraulic fracture may arrive at different interfaces. The mechanical properties and bounding quality of the interface as well as insitu stresses are among the most significant parameters that determine the interaction mechanism, i.e. whether the hydraulic fracture stops, crosses or experiences an offset upon its arrival at the interface. The interface could be a natural fracture, an interbed, layering or any other weakness feature. In addition to the interface parameters, the rock types of the two sides of the interface may affect the interaction mechanism. To study the interaction mechanism, hydraulic fracturing experiments were conducted using a true triaxial stress cell on two cube samples of 15 cm. Sample I had a sandstone block in the middle surrounded by mortar, whereas in sample II the location of mortar and tight sandstone blocks were changed. The results indicated that besides the effect of the far field stress magnitudes, the heterogeneity of the formation texture and interface properties can have a dominant effect in propagation characteristics of an induced fracture.

Impacts of Diverse Fluvial Depositional Environments on Hydraulic Fracture Growth in Tight Gas Reservoirs

2011 ◽  
Author(s):  
Patricia Helena Cuba ◽  
Jennifer Lynne Miskimins ◽  
Donna Schmidt Anderson ◽  
Mary Carr
Keyword(s):  
Hydraulic Fracture ◽  
Depositional Environments ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Tight Gas Reservoirs ◽  
Fracture Growth

Impacts of Diverse Fluvial Depositional Environments on Hydraulic Fracture Growth in Tight Gas Reservoirs

2013 ◽  
Vol 28 (01) ◽  
pp. 8-25
Author(s):  
Patricia H. Cuba ◽  
Jennifer Miskimins ◽  
Donna S. Anderson ◽  
Mary M. Carr
Keyword(s):  
Hydraulic Fracture ◽  
Depositional Environments ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Tight Gas Reservoirs ◽  
Fracture Growth

scholarly journals Study on Rheological Properties of Nanofluids

2021 ◽  
Vol 2132 (1) ◽  
pp. 012049
Author(s):  
Yan-qing Bian ◽  
Pu-cheng Wu ◽  
Jing Hao ◽  
Quan Shi ◽  
Guo-wei Qin
Keyword(s):  
Shear Rate ◽  
Rheological Properties ◽  
Oil And Gas ◽  
Loss Modulus ◽  
Production Capacity ◽  
Tight Gas ◽  
Water Control ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Tight Gas Reservoir

Abstract Based on the previous research on the rheological properties of nanofluids by many scholars at home and abroad, to solve the problem that the viscosity of conventional polymer water control agents is large and cannot meet the demand for increasing production capacity in the process of tight gas reservoir exploitation, this paper takes self-made nanofluids as the research object, tests the rheological properties of self-made nanofluids by rheological experiment, and systematically studies the effects of concentration, temperature and shear action on the viscosity of nanofluids, and the dynamic viscoelasticity and thixotropy of nanofluids were discussed. The results show that the rheological type of nanofluid belongs to power-law fluid, but it is related to the shear rate. The viscosity of nanofluids increases with the increase of concentration; when the temperature increases, the viscosity of nanofluids decreases and the fluidity increases; under the shear action, the viscosity of nanofluid changes very little and has good shear resistance; the dynamic viscoelastic test shows that the storage modulus G´ of the nanofluid is larger than the loss modulus G”, showing elastic characteristics; the thixotropy test shows that when the shear rate is accelerated, the viscosity decreases with time, and when the shear rate is slowed down, the viscosity recovers rapidly with time, which has good thixotropy. The research results provide an important theoretical basis for further research on the application of nanomaterials in tight oil and gas reservoirs.

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