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.
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
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.
Stress (or pressure) dependence of coal permeability is a commonly observed and generally accepted dynamic behaviour that is often ignored from production performance forecasting. Reasons for this omission typically include (a) the difficulties in reliably characterizing stress dependent effects from a limited number of pressure buildup tests, and (b) large uncertainties in our understanding of both the porosity and compressibility of coals. This paper demonstrates a new analytical workflow, and proposes a new set of equations that overcomes some of those limitations through acknowledging and accounting for stress dependent permeability (SDP) behaviour with radius - during testing and production - by translating expected permeability changes with pressure, to productivity changes with pressure gradient.
This paper utilizes a slightly modified form of Palmer-Mansoori (P&M) model in a workflow that includes Estimation of coal cleat volume compressibility using permeability-depth trends Characterization of mechanical skins from interpreted apparent skins Calculation of "stress dependent pseudo pressure" (SDPP) – converting permeability changes with pressure to productivity changes with pressure gradient – enabling the use of well productivities over time as part of a SDP characterization process The matching through regression of relative changes in well productivity indices in groups of wells - utilizing the SDPP approach – with a single stress dependent controlling parameter, in a way that is suited to extrapolating away from well control.
Estimation of coal cleat volume compressibility using permeability-depth trends
Characterization of mechanical skins from interpreted apparent skins
Calculation of "stress dependent pseudo pressure" (SDPP) – converting permeability changes with pressure to productivity changes with pressure gradient – enabling the use of well productivities over time as part of a SDP characterization process
The matching through regression of relative changes in well productivity indices in groups of wells - utilizing the SDPP approach – with a single stress dependent controlling parameter, in a way that is suited to extrapolating away from well control.
The paper provides the theoretical support for this approach via derivations from published models, and then outlines the methodology – sharing the results of a field example – demonstrating the relative ease with which the analytical process can be applied. Further, it highlights pitfalls of using well productivities as a direct proxy for permeability changes, or even utilizing coarse grid numerical simulation in the matching process. Finally, it also discusses further applications and limitations of its application.
This paper addresses existing knowledge gaps in the CSG industry by providing a simple, yet efficient, workflow for characterizing and incorporating stress-dependence of permeability in CSG Reservoir Engineering. This is achieved through the application of new analytical equations to characterize stress dependent pseudo pressure, enabling the direct use of well productivity changes, and can be used standalone, or as a means to accelerate a numerical history matching workflow.
Fogden, Andrew (FEI Oil & Gas) | Goergen, Eric (FEI Oil & Gas) | Olson, Terri (FEI Oil & Gas) | Cheng, Qianhao (Department of Applied Mathematics, Australian National University) | Middleton, Jill (Department of Applied Mathematics, Australian National University) | Kingston, Andrew (Department of Applied Mathematics, Australian National University) | Curtis, Mark (University of Oklahoma) | Jernigen, Jeremy (University of Oklahoma)
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.
"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.
Saudi Arabia has embarked on an exploration journey for its unconventional gas resources by recently targeting three different areas across the Kingdom. The targeted formations include tight sandstone, shale and tight carbonate with a permeability range of 200 nano-darcy to 0.1 MD. Extensive exploratory work has been performed in each of the areas through drilling vertical wells to identify and characterize potential targets through coring and open-hole logging along with flow potential testing of those targets after placing vertical fractures, which is beyond the scope of this paper. This paper highlights the progress of the unconventional program through drilling horizontal mono-bore wells and stimulating them with multistage fracturing using Plug-N-Perf technique. Three case studies, one from each targeted formations, are presented in this paper. The subjects addressed are:
Well completion including the selection of tubing and liner sizes, metallurgy and grades along with performing stress and thermal analysis simulating the expected loads during proppant fracturing to determine the maximum safe loads at each stage. Proppant fracturing design including the number of stages and clusters, the spacing of stages, proppant type, size and volume, and fracturing fluid systems. The design is based upon the geomechanical and petrophysical interpretations of the openhole logs together with onsite calibrations and measurements. Plug-N-Perf and fracture stimulation operations and execution Fracture fluid clean up and flow testing
Well completion including the selection of tubing and liner sizes, metallurgy and grades along with performing stress and thermal analysis simulating the expected loads during proppant fracturing to determine the maximum safe loads at each stage.
Proppant fracturing design including the number of stages and clusters, the spacing of stages, proppant type, size and volume, and fracturing fluid systems. The design is based upon the geomechanical and petrophysical interpretations of the openhole logs together with onsite calibrations and measurements.
Plug-N-Perf and fracture stimulation operations and execution
Fracture fluid clean up and flow testing
The paper summarizes the workflow adopted, the lessons learned and challenges overcome after drilling, completing, fracturing and flow testing of several unconventional gas wells in Saudi Arabia.
Sedimentary deposits and structural control on the depositional pattern in South Pine River basin has been investigated in the present study. The basin has attracted less attention in the past mainly due to its relatively smaller size and proximity to a larger basin. The basin is thought to carry signatures of past seismic activities and falls in the region south of crisscrossing fault zone. Previous studies in this area by
Digital elevation models (DEM) have been derived from contours at an interval of 5m available from published topographical maps and spot heights from USGS (2004) combined with sedimentological studies of exposed deposits were carried out along the South Pine River.
A fault trending N-S direction parallel to the major fault trend in this area was identified. The surface manifestations of the subsurface structure include a sudden change in the river morphology, change in the slope derived from DEM, confluence of the tributaries on approaching the fault zone and sudden changes in the sedimentary deposits. Alluvial fan deposits were identified on the downthrown block of the fault. Photographs of the sites were taken to record their characteristics. Minor seismic activity has also been recorded close to this fault (one of which was recorded in 1960) confirming its presence.
A combination of changes in lightning, vertical exaggeration and changes in the field of view of the DEM has proved to be very useful in identifying the location of the structure. This fault is thought to be a part of major fault system on the northern part of the study area. The concentration of fault traces decreases significantly from north to south as depicted from studies by
Mahoney, Shilo A. (The University of Queensland, St Lucia Australia) | Rufford, Thomas E. (The University of Queensland, St Lucia Australia) | Dmyterko, Anastasia S. K. (The University of Queensland, St Lucia Australia) | Rudolph, Victor (The University of Queensland, St Lucia Australia) | Steel, Karen M. (The University of Queensland, St Lucia Australia)
We report the effect of rank and lithotype on the wettability of artificial cleat channels in five coals from the Bowen Basin with ranks in the Rmax% range 0.98-1.91%. Wettability was assessed by measuring contact angles of air and water in the artificial cleats using a microfluidic Cleat Flow Cell (CFC) instrument. The artificial cleats were produced by reactive ion etching and had widths in the range 20–40 µm that replicate the width and shape of some natural coal cleats under sub-surface reservoir conditions. These model cleats were developed to allow systematic laboratory investigations of water and gas relative permeability behaviour.
Imbibition and drainage experiments were performed in the artificial channels using air and 0.1 %wt. fluorescein in fresh tap water to observe contact angles, the entry pressure of the air-water and water-air interface to the channel, and the pressure at which the channel was filled by the displacing fluid. Relative contact angles on the coal surface of 110 -140° were determined from images collected in the imbibition experiments. A trend of increasing contact angle with coal rank was observed. The low rank coal exhibited smaller contact angles and lower breakthrough pressures than the higher rank coal samples. In the drainage experiments the injection air displaced the water but left a residual liquid film on cleat walls across dull, inertinite rich bands. This residual film was not observed in the bright, vitrinite rich bands. The results of this study may provide the basis to consider an improved relative permeability model that explicitly accounts for wettability and the effect of coal rank.
Ramandi, Hamed Lamei (School of Petroleum Engineering, The University of New South Wales) | Armstrong, Ryan T. (School of Petroleum Engineering, The University of New South Wales) | Mostaghimi, Peyman (School of Petroleum Engineering, The University of New South Wales) | Saadatfar, Mohammad (Department of Applied Mathematics, Australian National University) | Pinczewsk, W. Val (School of Petroleum Engineering, The University of New South Wales)
An Australian bituminous coal is imaged at high resolution of 16.1 µm with (wet) and without (dry) X-ray attenuating fluids present in the pore space using a large-field three-dimensional microfocus helical X-ray computed tomography (micro-CT) instrument. Scanning Electron Microscope (SEM) is conducted on slices of the specimen to visualize coal micro-features up to resolution of about 15 nm. Two- and three-dimensional image registration techniques are used to precisely overlay micro-CT tomograms of the core plug in dry and wet conditions and SEM images to yield detailed three-dimensional visualizations of the geometry and topology of the fracture systems in coal. SEM images are also used to produce a calibration curve based on the relationship between the micro-CT intensity values and the true apertures of fractures within coal. This eliminates the need for two sets of imaging. Advanced filtering algorithms are applied to segment the micro-CT image into four distinct phases: resolved fractures, sub-resolution pores and fractures, macerals, and minerals. The application of micro-CT in determination of relative age relationships between adjacent geological features is presented. The distribution of resolved aperture size within the coal sample is investigated and the variation of permeability and porosity in several sub-samples of the coal is plotted. The analysis suggests that coal permeability is independent of porosity and is likely affected by other petrophysical properties such as lithotype. To include the effects of mineral phase on coal properties, we remove the segmented mineral phase and merge it to the resolved fracture phase. This analysis affirms that minerals are deposited in highly connected regions.
Multistage fracturing technique has considerably improved gas production from tight gas reservoirs all over the world. Well production is one of the main determining factors to assess the success of a fracturing treatment. In this paper, numerous vertical and horizontal wells drilled in the high pressure high temperature heterogeneous reservoirs have been evaluated to confirm effectiveness of stimulation treatments and benefits derived from the use of novel technologies. Among many variables that were analyzed include drilling, completion, and stimulation parameters such as well azimuth, completion types, fluid characteristics, acid strength, etc.
A database for stimulated wells was created and various parameters have been grouped and assessed to provide correlation and understand the effectiveness of fracture treatments and optimize development plan. Correlations were drawn using the Pearson correlation coefficient equation to compute data trend and ensure good quality data. Numerous, very useful plots are constructed and presented that show the different trends of the variables evaluated and how they affect production rate.
Analyses results indicate that use of real-time geomechanics is important to predict reservoir pressure and mud weight as wells are laterally drilled in the preferred minimum in-situ stress (smin) direction. This is because when wells are drilled along smin, they tend to become more unstable due to the higher stress acting on the wellbore. Accuracy in predicting stresses and pressures are keys to the drilling of such wells. The completion assemblies were selected between open hole multistage and plug and perforation cased hole approaches based of reservoir properties and hole conditions. The impact on production performance by using of non-damaging low gel loading fracturing fluids, high strength proppants, and optimal fluid and acid volumes have been demonstrated using actual field examples. The paper also illustrates the use of novel fracturing approach such as channel fracturing and its impact on sustained gas production in tight gas and making low productivity wells commercial.