SPE Asia Pacific Unconventional Resources Conference and Exhibition

In this paper, a method is proposed to determine the fracture toughness of brittle and heterogeneous material through hydraulic fracturing. The intent of the proposed method is to deploy it on materials whose are not easily determined by standard test. One example of such a material is hydrate-bearing sand, which is unstable under atmospheric pressure and temperature. The pressure-time record, injection flow rate and total volume injection are necessary information to determine the fracture toughness of the material using the classical linear elastic fracture mechanics approach. To verify the method, frozen sand is used as a substitute material and its fracture toughness found using the standard test. Frozen sand has similar composition as natural hydrate-bearing sediment except for the absence of methane gas and high pressure. Then, this method is applied on the hydrate-bearing sand.

Severe borehole collapse has occurred during extended reach drillingsin shale formations of Dongping Block, Qinghai Oil-field. An extreme difficulty is to choose mud weight lower bounds properly. Previous isotropic wellbore stability model does not consider the heterogeneities in transversely isotropic porous media like shale, thus fails to predict mud weight accurately. To solve the problem, a new wellbore stability modelis proposed; and an optimized nano-type drilling fluid is designed.whichcan be applied fordrilling operation.

The wellbore stability modelis developed through four steps: 1. The far-field stressesare transformed from an in-situ stress coordinate system to a borehole coordinate system; 2. An analytical solution for a near-borehole stress distribution in an elastic anisotropic formation under a transformed in-situ stresses regime is used, based on the complex-variable elasticity theory and the Biot's consolidation theory; 3. The around-borehole stressesare transformed from the borehole coordinate system to a weak-plane coordinate system; 4. An improved Mohr-Coulomb failure criterion is used to identify rock failure mode (along weak plane or through rock matrix) and to calculate the mud weight lower bound.

In addition, laboratory experimensts have demonstrated the ability for water-soluble hybrid nano-particles to plug shale matrix and micro cracks inside the shale, which helps to prevent chemical erosion of fluid to the rock. By sealing natural fractures with nanoparticles and optimizing mud weight using the new wellbore stability model, the borehole instability is effectively controlled. A procedure is also developed for wellbore stability analyses based on a comprehensive consideration of the formation property, the mud chemical property and the mud weight. This approach was applied to 12 deviated pilot wells drilled through shale formation in Dongping Block, where high pore pressure and natural fracture systems prevail: the mud weight is increased from previous 1.5g/cm³ to the present 1.85g/cm³. It is observed that the drilling time and the drilling complexities have been reduced by up to 52.4% and 62.4%, respectively, with significant cost savings.

Coal Seam Gas reservoirs are naturally fractured and the flow of fluid throughout the coal occurs by diffusion through the coal matrix and then via the cleats (network of fractures) towards the wellbore. Effective permeability of the cleats and Langmuir isotherm parameters of the matrix coal blocks are the key parameters in determining the economic viability of producing from a CSG reservoir.

Welltest analysis in CSG wells is more complicated than conventional reservoirs due to the stress sensitive permeability of the cleats and the great heterogeneity of coal. Fluid pressure inside the cleats initially controls the stress sensitive permeability. During production and at the reduced pressure near the wellbore region, the cleats have smaller aperture and less permeability than the cleats away from the wellbore due to the in-situ stresses. Conversely during injection, the cleats near the wellbore have higher permeability than the cleats away from the wellbore.

The common well test analysis methods normally provide undefined values of average permeability and skin factor, rather than addressing the effective permeability of the cleats. This study presents how to interpret the skin factor in a CSG welltest, and also proposes a methodology using integration of welltest analysis and image log data processing results for estimation of cleat characteristics in CSG reservoirs to be input in a dual porosity CSG reservoir simulation model.

In recent years, a number of Basin-Centred, Tight Gas Sands and Shale Gas Exploration Wells have been tested in Australia. Since monetization of the resulting Contingent Resources involves embarking on a multi-year, multi-billion dollar mega-project, most operating companies use a formalized Stage Gate Process to critically review the maturation of the business opportunity.

To obtain adequate resources and time to undertake Appraisal Drilling and Field Development Option Assessments, the project must pass through a Stage Gate-1 Review of the Exploration results and scoping-quality economic screening of the potential development concept. Concept generation often relies on ideas obtained from literature reviews and brainstorming, as well as data gathering trips to somewhat analogous operations.

This paper summarizes observations from a somewhat disappointing data gathering initiative undertaken in 3Q2015 in Calgary to talk with knowledgeable Canadians about learnings from their Deep Tight Gas Sand Developments.

These interviews reconfirmed that many of the field development planning (FDP) issues discussed in the literature and at technical conferences over the last 25 years remain in-play:

Significant resources and time should be allocated to the Appraisal TGS plays. Many existing projects initially suffered from inadequate access to properly preserved and representative core materials and/or rotary sidewall cores.

Recent trends in petroleum production have focused on developing unconventional gas reservoirs such as tight gas and shale gas. Considering worldwide shale gas resource potential, the largest resources exist in the former USSR and in North America, while for China, Central and Southeast Asia the estimated shale gas resource is 1115 TCF. Despite the smaller resource projection, this unconventional resource is of great interest for future development. In Thailand, the primary energy source is oil and natural gas, with 77% of electricity generated from natural gas (EIA, 2011). Yet current production is not enough to support the growing energy demand in Thailand, and there is increasing emphasis in exploring potential unconventional resources to meet this demand.

A study has been conducted to improve reservoir knowledge of the Huai Hin Lat formation, believed to be an important source rock for the gas fields in northeast Thailand. The Huai Hin Lat formation consists of fluvio-lacustrine sediments of Late Triassic. The formation is exposed along the margin of the Khorat Plateau. Petroleum exploration in Khorat Plateau has been ongoing since 1962 and two gas fields have been discovered and commercially produced in the Khorat Plateau since 1988.

Seven shale samples were taken from the Huai Hin Lat formation. All samples are the organic rich fine-grained rocks. The MicroCT technique was measured for porosity parameter. The average porosity of the samples was approximately 4.9%, and a pore size distribution was found. In addition, geochemical analysis was performed to determine total organic content (TOC) of the shale samples. The average TOC was found to be approximately 4.9%.

Permeability was measured for the seven samples using transient pressure pulse decay. The permeability range of the samples was found to be 90 (D to 280 (D and the average permeability of sample was approximately 180 (D. Permeability varies significantly because the shale is somewhat heterogeneous. Natural fractures present in the formation may also affect the value of effective permeability.

This paper provides details regarding the analysis of the Huai Hin Lat samples and the shale's rock properties as they relate to other commercial unconventional gas resources. The work is significant because there are few existing petrophysical evaluations of this formation. Results from this study will identify and highlight key reservoir parameters necessary to further assess the commercial potential of the Huai Hin Lat shale as a shale gas reservoir.

Petrophysical characterization of unconventional rocks is an important challenge faced by the industry for reservoir evaluation. In particular, characterizing the pore size distribution (PSD) of tight rocks is challenging due to their small pore size and presence of clay minerals. In this paper, we compare the PSD of shale samples using both of the adsorption and desorption isotherms of water (H₂O), nitrogen (N₂), and carbon dioxide (CO₂).

The shale samples are collected from three wells completed in the Horn River Basin. A setup is designed to obtain the water sorption (adsorption and desorption) isotherms for shale samples. The model developed by Zolfaghari and Dehghanpour (2015) is used to calculate the PSD of shale samples from water sorption isotherms. BET (Brunauer-Emmett-Teller) analysis is used to obtain the N₂ and CO₂ sorption isotherms, and their corresponding PSDs. Also, SEM (Scanning Electron Microscope) images of the shale samples are utilized to visualize the pores of the shale samples.

The comparative analysis of PSDs indicates that different methods give different PSDs. All of the calculated PSDs indicate that majority of the pores are smaller than ~10 nm. The portion of pores less than than ~1.5 nm is larger when the PSDs are calculated using the water sorption isotherms compared to that of the BET analysis. The PSDs calculated from the water sorption isotherms also show pores of larger than ~40 nm, which is in agreement with the SEM images of the shale samples. However, BET does not detect these large pores.

"Litigation against unconventional gas producers; lessons from the US experience."

Richard M Lightfoot, Casconsult Pty Ltd

In North America, exploration and production of oil and gas from unconventional sources principally shale, but also tight sandstones and coal seams – is more developed than elsewhere in the world. The presence of large shale, tight gas, and coal seam gas reserves has led to exploration throughout the world.

In Australia, the unconventional gas industry is most developed in Queensland, is seeking to expand in New South Wales and South Australia, and is prospective in Western Australia the Northern Territory, and, to a much lesser extent Victoria.

In the light of the US experience, which has included claims of mechanical failures and inappropriate waste treatment and disposal, leading to groundwater contamination, induced seismicity and hazardous fugitive emissions, government and scientific agencies have produced thousands of studies of the perceived benefits and risks associated with the gas.

In each jurisdiction where unconventional gas extractions has been proposed, governments have been developing legislative regimes for resource allocation and for the managing of risks, through statutes, regulations, standard, and codes of practice.

In the USA, landowners and other citizens who believe that unconventional gas extraction has caused damage to land, water, human and animal health, have resorted to ligation seeking to recover damages, principally by bringing tortuous claims in negligence, nuisance and trespass. In some jurisdiction, actions have also been based on strict liability and legislated rebuttable presumptions of liability.

The paper summarises some cases brought in the USA, to identify the basis of the claims and to analyse their outcomes. In particular, claims brought in tort, and the potential for such claims brought in Australia must be considered.

All sections of the Unconventional Gas Industry need to become aware of their continuing responsibilities. Corporations require an intimate knowledge of the law, its interpretation and the need to minimise exposure to financial, environmental and health risks.

Polymer crosslinked solutions support many beneficial applications in the oil industry, such as water shutoff and hydraulic fracturing. These techniques pose challenges, and, in order to reach a favorable result, high quality gels are required.

This study investigates the effectiveness of four zirconium-based, one aluminum-based, and one aluminum-zirconium-based crosslinkers that can be functional over a wide pH range (3.8 to 10) in crosslinking CMHPG (Carboxymethylhydroxypropylguar). Zirconium chemistry in aqueous solutions is quite complicated. Zirconium is prone to hydrolysis and readily polymerizes. It is highly sensitive to pH, temperature, and ionic strength. A high viscosity gel is a function of and a combination of the correct selection of crosslinkers, buffer systems, pH, polymer loadings, crosslinker concentrations, and temperatures. Not only do the type of ligands attached to the zirconium impact gel performance, but also the order of addition and reaction temperatures. Thus, two very similar crosslinkers can display very different performances.

This research further investigates the effects on gel formation of specific crosslinker concentrations (0.7 to 1.3 gpt) in a pH environment of 3.8 to 10.8. After forming a gel, the impacts of temperatures at 60 to 121°C (140 to 250°F) and the varying shear rates on the viscosity of formed gels were tested. The viscosity of crosslinked CMHPG using the crosslinker at a low pH (3.8) remained above 1,000 cp after 60 minutes at 60°C (140°F) and 10 s^-1. Increasing the shear rate to 170 s^-1 caused the viscosity to decrease to 300 cp. However, the viscosity stabilized at 300 cp for almost 40 minutes. At a low pH (3.8), delay curves were developed for the gelling process. The fast crosslinking reaction has always been a limitation of crosslinkers at high pH; however, the new aluminum-zirconium dual crosslinker in this study overcame this shortcoming. The optimum crosslinked gel was tested for proppant-carrying purposes along with the static leakoff tests. The results also revealed gel proppant-suspending capabilities and acceptable leakoff rates.

Extensive lab research undergirds a successful field treatment, and these results indicate that a high viscosity at high shear rates cannot be used to interpret the particle settling properties of a crosslinked gel. In addition, the chemistry of crosslinkers is very important as this study reveals that a viscosity buildup delay at a high pH, which has always been a shortcoming, is possible through the right choice of crosslinkers.

Understanding and prediction of hydrocarbon transport within the matrix of unconventional tight reservoirs demands an integrated imaging strategy spanning from the smallest nanoscale pores to plug scale and beyond. Recent developments in multi-scale imaging are presented for Barnett shale samples to illustrate this approach to upscaling. The utility of micro-CT imaging for shales can be extended by X-ray contrast enhancement techniques coupled with tomogram registration. In particular, saturation of a shale plug with a highly attenuating liquid and subtraction of this tomogram from the registered dry-state tomogram yields a 3D voxel map of connected porosity over the plug. The same procedure can be applied to sub-plugs sampled from the parent plug to capture micron-scale variations in porosity. This approach does not directly provide the size, shape and connectivity of individual pores, since the vast majority of shale pores remain below tomogram resolution even for small sub-plugs. Two approaches to access this higher-order information are addressed. The first uses the state of the shale sub-plug saturated with X-ray dense liquid as the starting point for dynamic micro-CT imaging of the diffusion of a second, miscible, X-ray transparent liquid into the sub-plug. This can reveal the presence of faster pathways of transport through pores of larger size or lower tortuosity. The second approach involves broad beam ion-milling of the sub-plug for acquisition of 2D BSEM image mosaics and mineral maps, and their registration into the corresponding section of the 3D tomograms. This provides a registered basis for upscaling of transport properties, e.g. simulated from small FIB-SEM cubes, to sub-plug and in turn to plug via their micro-CT porosity maps. Very high resolution SEM imaging of broken surfaces can provide useful complementary information as to the finest scale of organic-hosted nanopores. The Barnett shale samples exhibited fairly homogeneous distributions of porosity on the plug and sub-plug scales, and also displayed relatively uniform diffusion across the sub-plug, suggesting that they are amenable to characterization and upscaling using only a limited set of parameters. This homogeneity is thought to be due in significant part to the predominance of organic-hosted porosity and to the structural uniformity of these nano-scale organic pore networks.

The measurement of gas content of coals has been dominated by the standard methods of core desorption described by ASTM D7569 and AS3980 (1999). In this paper the limitations of these procedures are discussed with particular reference to the partial gas pressure the gas content is being referred to. Because the gas content is always quoted as an absolute value measured to an undefined gas partial pressure as opposed to a value at atmospheric pressure it brings into question the nature of the isotherm model being used at pressures below atmospheric. The generally accepted Langmuir model is found to be lacking at these lower pressures and alternative options are considered.

The current practise of measuring isotherms is also questioned, particularly with respect to mixed gas types where the extended Langmuir or IAS models are found wanting.

To overcome these deficiencies the process of measuring gas contents to known partial pressures of seam gas is used. So too is the process of measuring native isotherms on initial desorption of core. This is extended to the measurement of laboratory isotherms at reduced pressures.

The results of isotherm testing indicate that the native isotherms are generally not the same as isotherms derived from laboratory testing though they are more similar where the seam gas is of a single composition. By undertaking isotherm tests to lowered pressures we can see that there are shortcomings in the Langmuir equation and that gas storage at lowered pressures may vary substantially from this model. The measurement of gas content by conventional desorption needs to be measured to a known partial pressure and this needs in turn to be related to the isotherm.

This paper uses some basic science to produce better solutions to gas content analysis. Along with these developments comes the analysis of desorption of a sample and how this relates to the diffusion coefficient and core fracturing. This leads in turn to an improved process to determine the lost gas on core retrieval for coals and shales.