Southern Carnarvon Basin

Shales are omnipresent in sedimentary basins and generally need to be drilled through to reach conventional or to develop unconventional reservoir. Shales, especially smectite-rich, often cause significant drilling problems associated with overpressure, borehole instability, etc. Understanding of clay mineralogy before drilling is very important to reduce risks associated with drilling. In this study, we perform a simultaneous AVO inversion of a part of the Duyfken seismic survey, the Northern Carnarvon Basin of the North-West Shelf of Australia. Log data from a training well were used to establish correlations between smectite content and acoustic impedance (AI) and VP/VS ratio. It is worth noting that mechanically and chemically compacted shale exhibit two significantly different trends between smectite and a principal component of seismic attributes. The smectite content obtained from surface seismic is in a good agreement with that estimated in a blind test well from the XRD analysis of cuttings.

Presentation Date: Tuesday, October 16, 2018

Start Time: 1:50:00 PM

Location: 210A (Anaheim Convention Center)

Presentation Type: Oral

N. Muecke and A. Wroth, Vermilion Oil and Gas Australia; and S. Zharkeshov, R. Anton, I. McCourt, and N. Armstrong, Merlin ERD Limited Summary This paper shows how the implementation of a continuous-improvement process, in combination with precampaign-engineering and planning-optimization efforts, allowed the operator to expand the existing drilling-and-completion envelope in a mature offshore field. This provided a cost-effective means to access the remaining attic and undrained oil in a very shallow reservoir. Application of new technology, extended-reach-drilling (ERD) practices, complex completions, detailed engineering, good-quality real-time data, and execution support at the rigsite drove the evolution of well designs for the operator during the last 8 years, enabling the life of this mature asset to be extended. This paper highlights the evolutionary process applied to enable economic infield development, with an emphasis on relevant transferable learnings that might be ...

ABSTRACT: This paper revisits the problem of an elliptical planar fracture in a transversely isotropic (TI) material. Transverse isotropy can be used to represent the behavior of finely layered shale formations subject to hydraulic fracturing (HF). In contrast to isotropic homogeneous formations, in which penny-shaped vertical fractures are produced, the elastic anisotropy changes the aspect ratio of fractures. The latter aspect ratio of a uniformly pressurized (or ‘dry’) elliptical crack can be estimated for given TI elastic parameters. We extend this result to hydraulically driven fractures by using the near-tip asymptotic solutions of the crack for different regimes of propagation. The crack aspect ratios for the toughness-dominated regime, the viscosity-dominated regime, and the regime determined by yield stress of Hers chel-Bulkley fluid are calculated. The aspect ratio for the toughness-dominated regime is in agreement with the known solution for the ‘dry’ crack, while for other regimes the aspect ratio is different.

1. INTRODUCTION

Unconventional reservoir simulation has proved its economic success over the last two decades. This is a result of a combination of horizontal drilling and hydraulic fracturing (HF) techniques. In the process of HF, a highly pressurized fluid is injected into the rock formation to produce fractures. The HF technique enhances oil and gas recovery from low permeability shale formations by providing high conductivity pathways for hydrocarbons to flow (Economides and Nolte, 2000).

Unconventional rocks are known to be transversely isotropic (TI) (see, e.g., Jones and Wang, 1981, Hornby, 1998, Cho et al., 2012) which may affect the shape of the generated hydraulic fractures. To study this phenomenon, we consider the problem of an elliptical fracture in a TI material. The elliptical fracture produces an ellipsoidal crack-opening shape under uniform pressure loading, as was established for the isotropic case by Green and Sneddon (1950) and Sadowsky and Sternberg (1949). By using this result, Irwin (1962) derived the expressions for stress intensity factors and energy release rates at boundary points of the elliptical crack. Later Hoenig (1978) extended Irwin's solution to the anisotropic case by considering each point in the vicinity of the edge of the elliptical crack as a semi-infinite Griffith crack.

For the specific case of plane strain geometry, classical fracture modeling results can be extended to account for transverse isotropy if the appropriate elastic constants are used (Laubie and Ulm, 2014a). The latter study identified these elastic constants and discussed the application of the results to hydraulic fracturing. For the hydraulic fracture under consideration, transverse isotropy causes non-radial geometry that it characterized by the aspect ratio of the fracture's stable shape (Laubie and Ulm, 2014b). By applying the principle of maximum dissipation, Laubie and Ulm (2014b) found the solution for the stable aspect ratio for the ‘dry’ or toughness-dominated fractures.

ABSTRACT: Nine infill horizontal production wells were drilled in the Crosby, Ravensworth and Stickle oil and gas fields offshore Western Australia as part of the 2015 Pyrenees development plan. Prior to the drilling campaign, major concerns existed after encountering tight holes when drilling previous vertical and horizontal wells through the siltstones of Windalia Formation and shales of Muderong Formation, which are present above the reservoir section. As the kick-off point for the lateral wells would require high inclination angles (80° and above) that would cut through both Windalia and/or Muderong formations, borehole stability was a priority to be addressed. On top of that, lost circulation events in the Pyrenees reservoir sands in previous wells pointed out that the drilling window could become extremely narrow or nonexistent, as increasing the mud weight to keep the overlying Windalia and Muderong formations stable would potentially create lost circulation in the Pyrenees sands. Therefore, a comprehensive review of a legacy geomechanical model from the appraisal phase was carried out, and by incorporating laboratory rock measurements and drilling experience from the first horizontal wells, a fit-for-purpose model was calibrated and used as a planning tool, and eventually in the real time monitoring while drilling.

1. INTRODUCTION AND BACKGROUND

The Pyrenees development area is composed of three main fields, Crosby, Stickle and Ravensworth (Figure 1). It is located 45 km Northwest of Exmouth, and 35 km Southwest of the recently abandoned Griffin field, Western Australia.

The Pyrenees phase III drilling campaign started in April 2015 and ended in June 2016. The objective of the campaign was to drill and complete nine lateral producers along the three Pyrenees oil fields mentioned above. The wells were geosteered throughout the reservoir in average 10 ft below the top of the sands, to achieve a vertical offset from the oil-water contact as large as possible.

2. PAST DRILLING EXPERIENCE

2.1. Ravensworth

In the Ravensworth-1 well, after drilling 10 ft of new formation below the 9 5/8’’ casing, a formation integrity test (FIT) up to 12.6 ppg was performed. The following 8 A’’ section penetrated the Windalia, Muderong and Pyrenees formations with a 10 ppg mud weight (MW) and a couple of tight holes were experienced in the Windalia and Muderong formations while drilling and pulling out of hole (POOH). Additionally, 5-10% of cavings coming from the Muderong were observed at the shakers. The rest of the section was drilled without any instability issue.

ABSTRACT: The ability of shale formations to deform and seal the annulus around the casing has been documented in publications and industry presentations. Moreover, development of such natural seals (barriers) in the annulus has been utilized in Permanent plug and abandonment (PP&A) operations as an alternative to conventional PP&A methods and materials. It has been reported that this in fact facilitated the PP&A operations and resulted in considerable cost savings. The objective of this paper is to present the work done to assess the potential of the Gearle formation in the Griffin fields in the southern Carnarvon Basin in Western Australia with respect to its ability to provide a barrier during the PP&A operations. For this purpose, we identify first and second order factors controlling the creep deformation of shales/mudstones. In turn, we compared the material and mechanical properties of Gearle formation with the formations forming seal at NCS and also with other measurements completed on other shales globally. In addition, we have utilized simple numerical creep models to assess the creep potential of Gearle formation to form a barrier around the casing. Later during PP&A operations, we acquired IBC-CBL-VDL logs in the wells and observed evidence of bonding. We, finally, present the cement log bond interpretations in the intervals we observed casing-formation bonding.

1. INTRODUCTION

1.1. Background

Permanent plug and abandonment (PP&A), as common industry practice, is performed by setting a number of cement plugs inside the casing strings. In certain cases, annular seal, traditionally provided by annular cement, may not fulfil the abandonment requirements and rather costly remedial cementing, milling or cut and pull of casing has to be performed in order to complete the PP&A of a well. However, certain rock types, i.e., shale and salt, have the potential to satisfy the requirements for PP&A and can therefore be used as well barrier elements as long as they can be proven to have the required strength and seal around the casing over a sufficient interval. In particular, the ability of shale to deform and seal the annulus around casing to form a barrier has been documented with the experience of operators in the Norwegian Continental Shelf (NCS) in the North Sea -providing ease of operations and cost savings (Carlsen, 2012, Williams et. al, 2009).

Such 3D surveys are often accompanied by previously acquired 2D regional lines. Yet, due to the 2D nature and older acquisition technique, these 2D lines are usually of lower quality and contain more noise than the associated 3D data. In this project, we improve seismic image quality, identify regional features and local anomalies, and analyze seismic facies that are potentially related to hydrocarbon production in the Exmouth Plateau, North Carnarvon Basin, Australia, by simultaneously applying data conditioning, seismic attribute calculation, and Self-Organizing-Map (SOM) classification to multiple vintage 2D lines. Introduction The North Carnarvon Basin is a major hydrocarbon reserve in Australia (Chongzhi et al, 2013). It can be divided into sub-basins (Figure 1). Among these sub-basins, the Exmouth Plateau is the largest and cover most of the major gas fields. Thanks to such a prolific amount of hydrocarbon reserve, numerous seismic surveys have been acquired over the area.

Abstract

In this study, pore structures and water permeation property of a shale rock are analyzed by means of X-ray CT. The target samples are produced Kushiro district in Hokkaido, Japan. Underground of this area is consisted by Cretaceous formation. Firstly, one dimensional permeation tests were performed by using core sample retrieved from Cretaceous formation, and intrinsic permeability was evaluated. Secondly, the internal structure of rock samples was observed by X-ray CT scanner, and porosity distributions were also evaluated by comparing CT image data between the dry and the water-saturated conditions. It was found that Cretaceous formation has relatively low permeability as k=10⁻¹⁹ ~ 10⁻¹⁸ m². It was also found that the porosity of each sample was approximately 7%~13%, however, porosity distribution was not uniform, and was strongly influenced by density distribution in samples.

1. Introduction

Natural gas/oil has been developed all over the world, and most of gas/oil has been supplied from so called conventional natural gas/oil deposits for long time. However, as technology and geological knowledge is advancing, many unconventional natural gas/oil deposits have been discovered, and total amount of supplied energy is increasing [1]. The representative of unconventional natural energy deposits is shale rock layers [1]. In Japan also, there are several promising shale rock layers as gas/oil reservoirs [2], and certain amount of gas/oil deposits are inspected.

In this study, pore structures and water permeation property of a shale rock are analyzed by means of X-ray CT. The target samples are produced Kushiro district in Hokkaido, Japan. Underground of this area is consisted by Cretaceous formation. This is mainly formed by sandy shale and it is spreading under Kushiro coal seam. It is estimated that huge amount of methane gas exists in the Cretaceous formation [3], however, the origin of the methane and the storage process in the formation including its total amount are still not clear. The purpose of this study is to obtain fundamental characteristics or properties of the shale rocks located at Kushiro, such as nominal porosity, permeability, porosity and density distributions. Here, nominal porosity is evaluated through water absorption tests. One dimensional permeation tests are performed, and intrinsic permeability of the shale samples are evaluated. In order to inspect the internal structure of the shale, X-ray CT method is applied. From the CT image data, the internal structure of rock samples is discussed, and porosity distributions are also evaluated by comparing CT image data between the dry and the water-saturated conditions.

Summary

The offshore Wheatstone liquefied natural gas (LNG) project in Western Australia uses subsea big-bore gas wells as the preferred method of producing the field. Wheatstone wells use a 9 5/8-in. production conduit from the top of the gas pay zone to the ocean floor. Wellbores of this size are necessary to match the large productive capacity of the gas reservoirs they penetrate. This producing scenario provides the obvious benefit of yielding large volumes of gas through the use of relatively few wells. Each of those highly productive wells, however, also represents a source of gas that, if accidentally allowed to flow unhindered, could present an uncommonly difficult well-control challenge. It is for this reason that the Wheatstone Drilling and Completions (D&C) Team evaluated a wide range of possible reservoir- and well-architecture scenarios to fully understand the possible scale of relief-well responses that might be necessary in the event of a blowout. The conclusions from this evaluation were surprising. Our original well-design concept called for penetrating the Wheatstone gas reservoirs with a casing shoe set 3,100 ft vertically above. Our analysis indicated that three or four relief wells would be simultaneously required to bring a blowout under control. Because of these results, both the well- and drilling-execution plan were redesigned to minimize the number of required relief wells. In summary, the redesign amounted to setting the casing immediately (i.e.,<=10 ft) above the gas reservoir before actually penetrating it, with the resulting benefit of reducing the required number of relief wells to two. Although this reduction is beneficial, it should be noted that there is only one documented subsea case where two or more relief wells have been drilled with the intent of simultaneously pumping into both to effect a dynamic kill. Given this fact, our well-control-related preparations for executing this project were more extensive than those of preceding projects.

This paper chronicles the full extent of the engineering and operational planning performed to ensure that no uncontrolled hydrocarbon releases occurred during the execution of the Wheatstone Project’s subsea big-bore gas wells and, if a blowout were to occur, that the response to such an unprecedented event would be sufficient and robust. Covered in this paper are reservoir-deliverability modeling, dynamic-kill modeling, gas-plume modeling, relief-well trajectory and mooring planning, pilot-hole-execution planning, a newly applied logging-while-drilling (LWD) technology for sensing resistivity vertically below the drill bit, and a discussion of future research identified as necessary to better define the fluid-injectivity capabilities of subsea relief wells.

Characterization of flow processes in multi-scale porous system (nanopores to mesopores) in tight rocks, such as the shales, is challenging because of the coexistence of various flow regimes in the porous media. Although some methods based on dusty gas model (DGM) have been applied to determine the apparent gas permeability of shales (Javadpour 2009, Freeman et al. 2011, Sakhaee-Pour and Bryant 2012, Chen et al. 2015), they fail to describe gas flow process in nanopores in detail. In this paper, we present an innovative methodology for estimating apparent gas permeability of shales by coupling multiscale flow mechanisms. The Lattice Boltzmann Method (LBM) with effective viscosity and a general second-order boundary condition is used to analyze the various flow regimes involved in the single microchannel. The desirable agreement between the simulation results and that from the DSMC studies for the rarefied flow prompts the application of the derived correction factor for estimating permeability of shale gas reservoirs. In order to realize this, the porous medium is represented by a bundle of capillaries with diameters determined by mercury injection capillary pressure (MICP) curves. The porous flow is simulated by Darcy's law with derived correction factor; the surface diffusion of adsorption gas in kerogen pores is simulated based on Langmuir model and Fick's law. An extensive integration based on fractal dimension is performed to estimate the total flow rate and thereby the apparent permeability of typical shale samples. MICP and a transient pressure pulse technique are employed on 7 shale samples to obtain the pore size distribution and permeability. The result shows that the estimated gas permeability matches well with the measured permeability with a 20% variation, indicating that the physics based model presented in this paper is highly effective in predicting gas permeability of tight formations, such as the shales.

A development campaign offshore Australia, with a total of 15 laterals in a challenging geological environment, has been successfully completed by Quadrant Energy. The main objectives were to geosteer and place the well path at an optimum standoff from the oil/water contact (OWC), while drilling at the interface of the gas/oil contact (GOC), when present, and at 1-1.5m TVD from the reservoir top when not.

The field is characterized by a series of transverse and longitudinal seismic and sub-seismic faults that bisect hydrocarbon-bearing sands which represent the greatest challenges in this development campaign. Evidence from exploration wells showed a thin column of heavy oil and a gas cap in the fault-bonded reservoir. A new multi-disciplinary methodology not only enabled Quadrant Energy to achieve its development objectives, but to develop a full subsurface picture of the Coniston field reservoir.

The use of the Reservoir Mapping-While-Drilling (RMWD) combined with Bed Boundary Mapping Tool (BBMT) and Multi-Function LWD services enabled the laterals to be placed at 1-2m TVD below the reservoir top or gas cap, when present, even in highly faulted sections. In addition to this precise placement the extreme depth of investigation of the RMWD service, in conjunction with the real-time multilayer inversion capability, constantly mapped the OWC at a distance up to 19m TVD below the wellbore. While drilling, different qualities of reservoir sands were identified and enabled the extensions of the wells’ TDs based on reservoir properties. The distance to boundary information, provided in real-time by the RMWD service, was used in real-time by the Quadrant Energy geology and geophysics team to update and validate the seismic model that provided increased confidence in the reservoir model and a more precise planning for future development wells.

This paper will illustrate the use of the latest LWD RMWD technology in a challenging geological environment. The paper will explore the close collaboration, teamwork, and integration necessary to drive innovation and demonstrate the outcomes of this successful campaign which have not only exceeded the development goals, but have also generated a full 3D view of the reservoir.