Copyright 2007, Society of Petroleum Engineers This paper was prepared for presentation at the 2007 SPE Hydraulic Fracturing Technology Conference held in College Station, Texas, U.S.A., 2931 January 2007. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Hydraulic fracturing is a widely used technology in the petroleum industry to increase production rates from low-permeability reservoirs. It has also been successfully applied to coalbed methane gas development in many occasions. This paper presents an Australian field case of coalbed methane gas development where expensive fracture treatments did not yield the expected benefits. A comprehensive integrated geomechanical analysis was performed to understand the underlying causes for the failure. The geomechanical model consists of the magnitude and orientation of the three principal stresses, the pore pressure, and the rock strength. Fracture treatment data were used to estimate the least principal stress, vertical stress was determined from density logs, pore pressure was derived from direct field measurements, and rock strength values were determined from well logs and core measurements. The maximum horizontal stress (SHmax) magnitude was constrained by modeling the stress and pressure conditions consistent with the observation of wellbore breakouts in image logs. The relative magnitude of principal stresses corresponds to a transition between Strike-Slip and Reverse Faulting stress regimes (SV < Shmin < SHmax) with an overall SHmax orientation of NE-SW. Fracture propagation simulations using boundary element modeling showed that a complex fracture growth under the influence of the current in-situ stresses could be the main reason for the fracture treatment failure. The study recommended a number of alternative configurations for well orientations and fracture treatments in the field considering the existing in situ stress and the complex fracture network. Also the interactions between the coal seam and different fracturing fluids have been studied to evaluate the formation damage aspects to recommend the formation compatible fracturing fluid. Presentation of these results in this paper is expected to give a general framework for successful hydraulic fracture treatments

and example of specific implementation issues with respect to an Australian coalbed methane gas field. Introduction

Hydraulic fracturing is a process whereby proppant-laden fluid is injected into a well under high pressure to initiate a fracture from the wellbore wall and extend the fracture deep into the reservoir. Once the injection is ceased, the propped fracture becomes the principal conduit for flow of the hydrocarbon from the reservoir to the well, and thus achieving increased production rates. The petroleum industry has long been applying hydraulic fracturing treatment as a principal technique to improve oil and gas production. Of the production wells drilled in North America since 1950s, about 70% of gas wells and 50% of oil wells have been hydraulically fractured1. The technology has also been applied to many Coal Bed Methane (CBM) reservoirs. Improved design and execution of hydraulic fracturing treatments is, therefore, an important task in the petroleum industry. In fact, high demands for fracturing treatments in the industry have led to the wide commercialisation of this technology.

Despite many success cases, the operational performance and cost-benefit accounts of hydraulic fracture treatments have not been positive in some occasions, particularly onshore Australia2. Major difficulties encountered during treatments include the requirement of high injection pressure, high frictional pressure drop, inability to inject proppant at required concentrations within the pump capacity, inability to extend the initiated fracture, and consequently, poor post-stimulation productivity. These experiences in usual sandstone reservoirs have also been recently encountered in a (CBM) gas field in Australia (name withheld due to confidentiality agreement). Further improved understanding is, therefore, necessary to design and execute treatments that would be effective for such unconventional field conditions. Without field-appropriate design and execution of treatments, there is very little chance that fracturing programs will be successful to realise its potential benefits commensurate to its investments and expectations. This paper presents the Australian CBM field case where fracture treatments were unsuccessful. The objective of this paper is to investigate the causes for failures of the treatments carried out through an integrated geomechanics analysis and to suggest measures that could be taken to increase the likelihood of success.

Field_1 is owned by Operator_1 and it contains a CBM reservoir with a shallow thickness (about 11 ft) and hydraulic

SPE 106276

Implications of Geomechanical Analysis on the Success of Hydraulic Fracturing: Lesson Learned From an Australian Coalbed Methane Gas FieldKhalil Rahman, SPE, U. of Western Australia, and Abbas Khaksar, SPE, Helix-RDS Australia

2 SPE 106276

fracture treatments were carried out to increase gas production from the reservoir. Without much reservoir characterisation, Service_Co_1 was contracted to carry out fracture treatments, 23 wells were fractured with great enthusiasm on both sides. Fig.1 shows fracture treatment history for one well, and the comment from the operating company was as follows:

Fig. 1: Injection time versus pressure history during fracturing a well in Field_1 Great effort by the frac team to move equipment and rig up and complete final frac prior to long weekend. This was achieved in +40oC. Very much appreciated by Operator_1. I knew you could do it. Hope to see the same faces in our next frac campaign. Overall rating (0-100%) 95% - I do not give 100% (always room for improvement), signed and dated 25/06/01.

Unfortunately, soon the disappointment became bigger than the enthusiasm when post-frac well production did not go nowhere near to the expected/predicted rate. This prompted to undertake a comprehensive study from the drilling phase, to reservoir characterisation, geomechanics modelling and finally fracture treatment design. Experimental and associated computational studies were carried out to characterize mechanical and petrophysical properties of the coal seam including (1) mechanical properties of CBM reservoir rocks, (2) in-situ stresses, (3) bulk matrix porosity, (4) matrix permeability, (5) surface chemistry evaluation of gas/water systems, and (6) absolute and relative permeabilities to water/gas systems with core flooded by fresh water, linear gel and cross-linked fracturing fluids.

This paper will elaborate further an integrated geomechanical model and investigations into causes for failure based on fundamental principles of hydraulic fracturing, and finally recommend a series of measures to maximise the likelihood of success.

Integrated Geomechanical Study The geomechanical model consists of the magnitude and orientation of the three principal stresses, the pore pressure and the uniaxial compressive rock strength (UCS).

Mechanical properties including Youngs modulus, Poissons ratio, compressive strength, cohesive strength and angle of internal friction of coal samples from the reservoir were determined. Tests were conducted in a triaxial test apparatus at different confining pressures. The uniaxial

compressive strength derived from triaxial compressive tests varied from 31.56 MPa to 39.45 MPa. The Youngs modulus, estimated by secant approach, varied between 3.05 and 4.2 GPa. The range of Poissons ratio was found from 0.2 to 0.33. The cohesive strength varied between 8.15 and 10.11 MPa, and the internal friction angle varied from 35.4 to 38.3 degrees. Due to the limitation of sample size and heterogeneity and anisotropy of the coal seam, the representability of the triaxial test results was, however, still considered to be limited. Note that the characterized values of these parameters are required for in-situ stress characterization, hydraulic fracturing design optimization and wellbore stability study.

Empirical relationships between UCS and the P-wave velocity (sonic log) were used to derive strength profiles for sandstone and shale sections. Log-derived rock strengths in Sandstones and shales adjacent to the coal seams range between 70 MPa and 100 MPa. In-situ Stress Characterization

Vertical Stress (Sv) and Pore Pressure (Pp). The estimation of vertical stress was relatively straightforward by simple integration of density log data:

=H

fv dHgS0

(1) where: Sv is the vertical stress; g is the gravitational acceleration; f is the formation bulk density, H is the subsurface depth from the surface and dH is the differential depth.

The log data was available at very reasonably small depth intervals with very smooth variations and therefore a simple trapezoidal rule for individual intervals and their progressive summation easily implemented the above integration. Only one difficulty was that some density log data was missing, and a density of 2.31 g/cm3 was assumed for the missing portions, resulting in a vertical stress gradient of 1.1 psi/ft at reservoir depth interval. Direct pore pressure measurements indicate a normal pressure gradient (0.43 psi/ft) at reservoir depth.

Minimum Horizontal Stress (Shmin). The first obstacle to stress characterization was the unavailability of any reliable Leak-Off Test (LOT), or Extended Leak-Off Test (ELOT) data. The actual fracture data, injection pressure versus time/rate for 23 wells was however made available.

As can be seen in Figs. 1, 2 & 3, the actual fracture data was plotted over a long injection time scale, and therefore identifying the breakdown pressure was difficult. We also encountered difficulties with identifying the instantaneous shut in pressure (ISIP) and fracture closure pressure (Pc). The difficulty with ISIP was that not enough time was allowed for pressure to decline after shut in, giving a short tail uncertainty. Also in some instances, data was lost on the pressure curve after the well was shut in, giving a bleed off uncertainty. Some of these uncertainties are shown in Figs. 2 - 3. All these uncertainties were scrutinized very strictly, and only reliable data were used in analysis. G-function and time-function graphs3,4 were plotted to improve the accuracy in ISIP and Pc. Average closure pressures (Pc) and ISIP were taken from a

SPE 106276 3

number of such plots for a well. The minimum horizontal stress, Shmin was then approximated as:

2minc

hPISIPS += (2)

Fig. 2: True ISIP and uncertain breakdown pressure for a well in the Field_1.

Fig. 3: True breakdown pressure but uncertain ISIP for a well in the Field_1.

Only five reliable breakdown pressures could be obtained from the fracture data. There is a fair amount of scatter in these values perhaps due to the complex nature in which coal fractures and the heterogeneous nature of the coal seam. The range of scatter is from 2600 to 3200 psi. The minimum horizontal stress also showed scatter and for some wells we could only obtain a possible range while for others only a maximum value was obtained. However, if the cases with question marks and the outliers (Well#15, 3449 psi and Well#14, 1659 psi) are taken away there are 13 wells with minimum horizontal stress between 2500 and 3100 psi (Table 1). This is a similar range of scatter to the breakdown pressures and is quite acceptable considering the complex nature of fracturing.

Most of the results show that the minimum horizontal stress is close to or greater than the vertical stress indicating that the filed is subject to reverse faulting (RF) stress regime, which is consistent with the regional stress data5. The

summary of characterization of minimum horizontal stress and vertical stress is presented in Table 1.

Orientation and Magnitude of Maximum Horizontal Stress (SHmax). The azimuth of the maximum horizontal stress, SHmax can be obtained from borehole breakout data. In vertical wells, this stress direction is approximately 90 deg. from the breakout direction. Stress-induced wellbore breakouts occur when the compressive stress concentration around the borehole wall exceeds the rock strength. The presence, orientation, and severity of failure are a function of the in situ stress field, the wellbore orientation, and the rock strength6. Figures 4 and 5 show examples of borehole breakouts observed in acoustic image data collected in two vertical wells drilled in the study area. The overall orientation of SHmax is NE-SW, which is inferred from the borehole breakout data.

Using fracture data, wellbore breakout data (Fig. 4 and 5), mechanical strength properties, drilling data and pore pressure, a more rigorous stress polygon modeling6 was carried out to establish the ranges for Shmin and SHmax (Fig. 6). Stress modeling indicates that the (SHmax) magnitude is significantly greater than the SV and the relative magnitude of principal stresses corresponds to a transition between Strike-Slip and Reverse Faulting stress regimes (SV < Shmin < SHmax) this is consistent with the regional stress condition5.

0 360

Top of Image data

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Fig. 4. Well logs and examples of image data collected in the well_A. Borehole breakouts in the acoustic image (right figure) are visible on the Flat Screen View image as two diametrically opposed fuzzy dark bands (indicated by white arrows) about 180 apart and have approximately the same width. The distinct white band, visible on the 360 Degree Transit Time view on the far right, is indicating the elongations. Also shown are well log profiles from 650m to 697m MD, corresponding to the image log coverage, showing gamma, caliper, density and sonic log, breakout azimuth and log-derived rock strength for sandstone and shale sections.

4 SPE 106276

Coal

Sst.

Sst.

Very wide Breakouts (washed out) in Coal at this depth.

30-50o wide Breakouts in Sandstone

Breakout rotations associated with natural fractures

Fig. 5. Example of borehole breakouts observed in well_B. Breakout width in sandstones above and below the coal seam is limited to 30 to 50. The dark horizontal band in the Flat Screen View (indicated by the blue arrow) and the fuzzy and white color section in the 360-degree transit time view at 631.5m depth are indicators of very wide breakouts (washed-out) in the coal section. A rotation in breakout azimuth may be associated with natural fractures at 633m.

SHmax

Shmin

SHmax

Shmin

Fig. 6: Stress modeling to constrain the SHmax magnitude based on observations of wellbore failure in the sandstone unit at 631 meters depth (immediately above a coal seam) in well_B (Figure 5). The area within the polygon indicates the complete range of permissible stresses based on frictional faulting theory (Zoback et al 1985). The pink contour line indicate combinations of Shmin and SHmax for a given compressive rock strength (UCS) that lead to the occurrence of wellbore breakouts (shear failure). Pore pressure at the modeling point is near hydrostatic with this section being drilled balanced. The vertical stress is 2300 psi and fracture test data indicates Shmin is equal to or higher than Sv. The log-derived rock strength at this depth is ~10500 psi (72.5 MPa). The resulting range of SHmax is 5050 -5400 psi (34.8-37.5 MPa) at this depth which indicates transition between strike slip and reverse faulting stress regime (Sv < Shmin < SHmax).

Implication of In-situ Stress on Hydraulic Fracturing One of the most important elements in successful hydraulic

fracturing design is the characterisation of the in-situ stresses. In many cases however in-situ stress characterization is not performed to design and plan hydraulic fracturing. If any fracture treatment is designed at all, it is done based on some assumed values of in-situ stresses. The design of fracture treatments carried out in the CBM field was not an exception from this practice. When investigated the design basis of treatments carried out, we found that a standard vertical stress gradient, 1.1 psi/ft, was assumed and then the minimum horizontal stress was assumed to be 40% of the vertical stress. Irrespective of numerical values of in-situ stresses, the above assumption clearly considered a normal faulting stress regime, whereas the in-situ stress characterization in the previous section has revealed the existence of a transition stress regime between strike-slip and reverse faulting stress regimes. Through our fracture treatment redesign study, we found that the target fracture geometry should have been achieved easily with a minimal treatment pressure using a fraction of the equipment capacities used if the field had the assumed normal faulting stress regime. The field experience was, however, on the contrary. The people involved with pumping at the field acknowledged that they encountered unexpected formation resistance, and they completed pumping in several stages with significant pressure rise in each stage. Fig. 1, although the fairest one among others, is a hard evidence of their acknowledgement in which we can see a number of screen-out peaks. Among other reasons, the role of in-situ stresses was inferred for this type of injection experience.

It is now widely-available knowledge in the petroleum industry that fracturing of vertical wells in the reverse faulting stress regime results in a horizontal component of the fracture. This is because when the fracture becomes horizontal, it encounters a minimum resistance from the vertical stress, which is the minimum in a reverse faulting stress regime. This is also predictable by the mixed-mode theory of fracture mechanics. Although initiation of a transverse fracture directly from the wellbore wall is a possibility in a reverse faulting stress regime, even if the initial fracture is longitudinal (vertical) at the near-wellbore, it eventually becomes transverse (horizontal) during propagation under the influence of far-field in-situ stresses. Actual research results of such fracture reorientation and its quantified effects on fracturing pressure are, however, rare. This is mainly because the 2D, P-3D and even the so called 3D fracture models used for hydraulic fracture treatment design are not developed to consider complete 3D convolution of fractures in space. Also most of the true 3D fracture models are developed for small fractures and not suitable for massive hydraulic fractures involving coupled stress-deformation and fluid flow phenomena. One notable recent development is HYFRANC3D7 which has such capability although extremely limited by computational requirements.

Hossain et al.8 showed through stress modeling that a transverse fracture may initiate directly from a vertical wellbore in an extreme reverse faulting stress regime if it satisfies the following condition, ignoring the effect of pore pressure and tensile strength:

SPE 106276 5

2minmaxv

hHS

SS + (3)

Even the extreme combination of in-situ stresses in the

field (SHmax = 38 MPa, Shmin = 16.5 MPa, Sv = 15 MPa and = 0.33) does not satisfy the above criterion. It is therefore most likely that a longitudinal fracture initiated from the wellbore at an approximate pressure that can be estimated as follows:

maxmin3 Hhwf SSP = (4)

The longitudinal fracture along the non-preferred propagation direction then reoriented itself to be horizontal under the influence of the far-field reverse faulting stress regime.

Fig. 7: Model for hydraulic fracture propagation by HYFRANC3D.

Using HYFRANC3D, model-scale hydraulic fracture propagations were simulated in the non-preferred direction to understand the magnitude of effect on propagation pressure and fracture volume, as an indicator of flow conduit. The model for fracturing in horizontal well along h is shown in Fig. 7. The model was stressed by a normal faulting stress condition; Sv (or v) = 68.95 MPa, SHmax (or H) = 55.16 MPa and Shmin (or h) = 43.44 MPa. Although the well orientation favors propagation of a transverse fracture, the stress condition is not suitable for a direct transverse fracture initiation. According to hydraulic fracture initiation theory, a longitudinal fracture would initiate along Sv direction, i.e. along top and bottom directions of the wellbore. A penny-shaped fracture was created along Sv direction and stepwise propagation was simulated by a constant injection rate. The convoluted fracture shape due to non-planar propagation is shown in Fig.8.

The cumulative fracture volume and the fracture pressure versus crack size are plotted in Fig. 9, which shows a sudden increase in fracture pressure with reduced fracture volume after a few steps of propagation. It is clear from Fig. 8, the propagated fracture tended to be transverse to the wellbore axis through severe turning and twisting and consequently

requiring increased fracture pressure and resulting in a reduced fracture volume (Fig. 9).

Fig. 8. Convoluted fracture shape due to non-planar propagation.

Fig. 9. Propagation pressure and fracture volume due to fracture reorientation.

Although the stress magnitudes and the well orientation in our coal seams are different from the above simulated example, we should expect similar behaviour, because the vertical stress is the minimum and it is along the vertical wellbore axis. A longitudinal fracture would be initiated along SHmax direction and then through turning and twisting it would try to be transverse to the vertical wellbore axis (i.e. horizontal fracture). Consequently, the treatment pressure would rise sharply. From interview of field people, it was clear that similar experience was encountered during treatment, and therefore they tried pumping fluid in a number of stages after every pressure rise; the source of many screen-out peaks in Fig. 1. Although certain volume of fluid was possible to pump in, the fracture growth and fracture conduit were very little to realize the predicted production.

6 SPE 106276

Fracturing Fluid-Induced Formation Damage Apart from fracture geometry design consistent to in-situ stresses, it is very important to use a formation compatible fracturing fluid to minimize formation (permeability reduction). When exposed to fracturing fluids, formation damage of coal seams is usually induced by two mechanisms: matrix swelling and cleat plugging. Coal formations usually contain a certain amount of clay minerals such as smectite and illite, which usually swell when exposed to water-based fracturing fluid filtrate. This swelling could cause an irreversible permeability reduction. However, mixing KCl salt with right concentration can minimize this effect for many clay materials. Cleat plugging by hydraulic fracturing fluid, on the other hand, can be minimized my mixing surfactants that improve the cleaning (recovery) of the fracturing fluid and reduces the permeability reduction by water sensitivity. These surfactants basically reduce the wettability and surface tension by affecting the contact angle. Investigation of these issues required standard laboratory tests including petrophysical characterizations. Porosity and Permeability

Porosity of coal formations in the field was characterized first. Core samples from two wells at a reasonable distance were taken for the study. For Well_1, the coal seam was at 2210 ft depth, whereas this depth was 2000 ft for Well_2. Four samples were prepared and tested from each well. The average porosity was found to be 1.61% for Well_1 and 2.72% for Well_2. This represents very low porosity of the coal seam and its significant spatial variation.

The matrix permeability to gas was measured for the two wells at different confining pressures using a number of samples. A standard gas permeameter apparatus was used in conjunction with Darcys law for this purpose. Figs. 10 and 11 present permeabilities as functions of confining and mean pressures. The mean pressure is defined as the average of upstream and downstream pressures, and the effective confining pressure is defined as the difference of applied confining pressure and the mean gas pressure.

0.0100

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eabi

lity

(mD

)

conf 200psiconf 400psiconf 600psiconf 800psiconf 1000psiconf 1200psi

Sample: Diameter=6.072cm, Length=14.66cmGas: Helium

Fig. 10. Matrix permeability for sample_1 from Well_1

The effect of confining pressure on coal permeability is found to be quite significant. Permeability decreases dramatically with increase in confining pressure representing the high compressibility of coal seams. The variation of coal permeability with respect to mean gas pressure within the coal sample was found generally to follow Klinkenberg effect with some exceptions at high level of upstream pressure where permeability to gas increases with increase in mean gas pressure. Coal permeability is strongly dependent on the presence of fracture and cleat system, which probably caused a wide variation of permeability in different spatial locations.

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eabi

llity

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conf 200psiconf 400psiconf 600psiconf 800psiconf 1200psiconf 1500psi

Sample: Diameter=6.097cm, Length=14.67cmGas: Helium

Fig. 11. Matrix permeability for sample_1 from Well_2 Surface Chemistry Study

To evaluate the wetting and cleaning quality of various fracturing fluids, the surface chemistry behavior was investigated by laboratory measurement of changes in interfacial tension and contact angle of linear gel and cross linked gel fracturing fluid systems. The surface tension of linear and cross-linked gel fracturing fluids was measured using Kruss Interfacial Tensiometer. The contact angle was determined by direct measurement from sessile drop profile. A micrometer pipette with small tip forms a drop of fluid on the surface of a flat coal specimen placed on a horizontal stage. Illumination of the drop was supplied from behind. The profile of the drop was captured by a camera mounted on a telescope and the photograph was analyzed using a image process system and then the angle was measured as illustrated in Fig.12.

Results are presented in Table 2. The surface tension is found to have a tendency to decrease after gel fluids were broken, but the difference was not significant, about 5% for cross-linked gel and 10% for linear gel. The cross-linked gel fluid has significantly lower surface tension than the linear gel fluid, indicating that the cleaning of both fluids is almost similar and very much dependent on successful gel breaking. The contact angle measured on split surfaces was significantly smaller than that measured on cut surfaces. Since the split surface is more representative to the native surface condition,

SPE 106276 7

the coal seems to be intermediately wet and has a tendency to be both linear gel wet and Cross-Linked gel wet. The contact angle of fresh gel fluid is fairly close to that of broken gel fluid. Thus, it can be concluded that in terms of wetting quality from coal seam there is very little difference between the linear gel and the cross-linked gel as fracturing fluids.

Fig. 12. Contact angle of broken linear gel on the split surface of a core. Core Flooding Study

Core flooding tests were carried to evaluate the permeability impairment of coal seams in contact of water, linear gel and cross-linked gel as fracturing fluids. A fracturing fluid flooding/injection apparatus was established to flood fracturing fluid through coal samples. The fracturing fluid was isolated from water inside a piston-type separator. A volumetric micro flow pump was used to drive the piston and apply pressure to the fracturing fluid, which floods through the coal sample. A water/gas relative permeability measurement apparatus was used to measure water/gas relative permeability after fracturing fluid flooding.

Once the sample was saturated with fresh water, fracturing fluid was injected into the sample, and effluent was collected at the outlet. The flood test was terminated after two hours of injection. The sample was then kept for 6 hours to allow breaking of gel. Helium gas was then injected to the sample and relative permeability was determined by using the unsteady-state gas displacement procedure. Finally, the sample was re-saturated with water and permeability to water was determined.

After 48 hours of water flooding with one sample having relatively high permeability, about 30% permeability reduction was observed (as shown in Fig. 13) most of which was, however, recovered after back flashing. Relative permeabilities to water and gas of the same coal sample were then characterized before and after the linear gel flooding (Fig.14). The absolute permeability to water after the linear gel flooding was measured to be 22.4 mD. These show that the absolute as well as relative permeabilities were not much affected by the injection of linear gel fluid. Another core sample was flooded with a cross-linked gel fluid. The absolute permeability to water was measured to be 5.07 mD before flooding and 2.36 mD after flooding. Relative permeabilities to water and gas were also measured before and after the flooding (Fig. 15). With another very low permeability core sample, the absolute permeability reduced almost 10 folds from 0.093 mD to 0.0095 mD.

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Fig. 13. Effect of water injection on permeability of one core sample

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Fig. 15. Relative permeabilities of another core sample with cross-linked gel flooding.

61

8 SPE 106276

Thus, these tests established that both water (or water-based fracturing fluids) and linear-gel fracturing fluids are suitable for the coal seam.

Recommendations Unless some kind of mechanical devising system can be implemented to initiate a horizontal fracture directly from the vertical well, the fracture turning and twisting problem in the vertical well in the reverse faulting stress regime is very unlikely to avoid. However, a treatment with very negligible proppant concentration in the initial stages could have been attempted in contrast to the approach taken in the field, i.e. higher concentration in the initial stages.

From production considerations, a horizontal well along Shmin direction could be a better option in such a thin reservoir ( 11 ft pay thickness) where the production potential could be maximized by a number of transverse circular fractures. A direct transverse fracture initiates from such a well if the in-situ stresses satisfy the following condition8:

2min

maxh

HvSSS + (5)

The in-situ stresses in the reservoir, however, do not

satisfy this criterion, and therefore a transverse fracture would not be initiated automatically. Even if a mechanical system is devised to create transverse (vertical) circular fractures directly from the horizontal well, the fractures may turn to be horizontal again leading to the similar complexities encountered with longitudinal fractures from vertical wells. Further discussions of transverse fractures from horizontal wells are presented in many references9-12. Joshi13 recommended avoiding transverse fracturing of horizontal wells if secondary recovery mechanisms are applied. This is because such fractures cause short-circuiting of the injection fluid, resulting in early breakthrough and poor sweep efficiency.

Fig. 16. Required mud weight to maintain wellbore stability (collapse pressure), fracture breakdown pressure and minimum stress as a function of hole azimuth for horizontal well at 630 m TVD.

Fig. 16 plots the collapse pressure (mud weight required to maintain borehole stability), formation breakdown pressure (initiation of hydraulic fratcure at the wellbore wall) and minimum horizontal stress for horizontal wells a function of horizontal well azimuth at 630 m TVD. According to the stress condition, horizontal wells drilled along NE and SW directions (SHmax direction) will be more stable as they would require the least mud weight for borehole stability during drilling (Fig. 16). However, because of the relative magnitude of the in situ stresses, horizontal wells drilled parallel to the SHmax direction would require extremely high pressures to breakdown the formation during hydraulic fracturing. In contrast, horizontal wells drilled in NW and SE directions will require the highest mud weights to maintain stability whilst the formation breakdown pressure will be at its minimum in these directions, making well control difficult during drilling. Therefore, horizontal wells drilled in directions with oblique angle with the SHmax and Shmin azimuths, would be optimally oriented for both wellbore stability and hydraulic fracturing purposes.

A number of longitudinal horizontal fractures at the mid-depth of the horizontal well would be more productive than a fractured vertical well that has been tried in the field so far. A cemented completion is preferred if a horizontal well is to be fractured, because open holes or slotted liner holes cause large leak-off along the length. From a mechanical standpoint, the horizontal well needs to be isolated in several zones along its length by using bridge plugs and then various zones can be fractured in stages. From the fracture treatment design point of view, the fracture length along the well can be treated as the fracture height (hf) whereas the lateral extent of the fracture can be treated as the fracture half-length (xf). It is easily comprehendible that hf>>xf for feasible zone isolation. Thus, the fracture treatment can be optimized using KGD fracture model for each zone.

An alternative hydraulic stimulation technique14 called shear-dilation has also high potential to be successful in the reservoir, because it contains natural fractures and the coal seam has been found to be relatively insensitive to water flooding. By employing shear-dilation principles, a hydraulic stimulation can be adjusted to activate the network of pre-existing natural fractures, instead of creating conventional two-wing coplanar massive fractures. This technique has been found to be successful in stimulating natural gas and coalbed methane reservoirs in many places in the world15-17, particularly in the East Texas Cotton Valley and Black Warrior Basin Coalbeds in the USA.

Multi-stage hydraulic fracturing with production intervals might be another alternative stimulation technique for the field. A non-uniform change in pore pressure during production from a vertical well fractured by a small treatment is expected to change the stresses in the reservoir, and thus may influence the refracturing behavior. To exploit this phenomenon, the overall stimulation process can be completed in a number of stages allowing the well to produce over an appropriate period of time between stages. This may allow the growth of a productive vertical fracture in a vertical well even in the reverse faulting stress regime. A recent pilot project demonstrated its potential with respect to a small-scale reservoir18. Further study is, however, necessary to investigate

SPE 106276 9

the effectiveness of this production-intervaled multi-stage fracturing/refracturing technique applying the modeling technique to a real-size reservoir and deploying the technology to the field.

Summary and Conclusions A coalbed methane reservoir was hydraulically fractured with vertical wells without characterization of reservoir properties and the in-situ stresses. A normal faulting stress regime was assumed to design treatments that were carried out. Screen-outs were observed/experienced during execution of treatments; however, a certain amount of fracturing fluid was possible to pump in each case in a number of stages, which was deemed to be the success of a treatment. Production tests revealed that the treatments were ineffective. As part of this study, the in-situ stresses were characterized rigorously together with other reservoir properties. A reverse faulting stress regime is found to be dominant in the reservoir. Fracture propagation simulation by HYFRANC3D, a boundary element based tool, proves that a vertical fracture initiated from a vertical well in such a stress condition would reorient itself to be horizontal through severe turning and twisting. Consequently, the fracture extension process would require an extremely high pressure (a source for screen-outs experienced in the field) and severely constrict the fracture conduit (responsible for low productivity experienced).

Recommendations for potentially effective alternative treatments include multistage longitudinal/transverse fracturing of horizontal wells, shear-dilation stimulation and production-intervaled multistage fracturing of vertical wells. Design implications and need for further research study for these different treatment modes have been discussed. Also the detailed treatment design and economic analysis have not been performed in this study. Therefore, the recommendations should be taken as suggestive rather than prescriptive.

Issues of formation damage aspects during fracture treatments have also been addressed with experimental data using actual core samples from the coal seam. As expected, the coal seam was found very heterogeneous in terms of porosity and permeability. In terms of wetting and post-treatment cleaning aspect, both linear gel and cross-linked gel fluids are found to be of very similar quality. The core flooding tests however revealed that the cross-linked gel fluid would severely affect the relative permeabilities to gas and water as well as absolute permeability to water. The absolute permeability is slightly affected by water flooding in relatively high permeability cores, which could be recovered by back flashing.

The planning and design of hydraulic fracture treatments is an important part of the process. The success of an effective treatment, however, fully depends on realistic values for reservoir properties, economic parameters and realistic modeling of the design process. This requires integrated reservoir characterization, geomechanical modeling and fracture treatment optimization by modeling and laboratory experiments. References 1. Valko, P., and Economides, M.J.: Hydraulic Fracture Mechanics,

Wiley, Chichester, England, 1995.

2. Rahman, M.M., Rahman, M.K. and Rahman, S.S.: The Recognition and Alleviation of Complexity with Hydraulic Fracturing Onshore Australia, Journal of the Australian Petroleum Production & Exploration Association Limited (APPEA Journal), pp.469-480, 2000.

3. Weng, X., Pandey, V., and Nolte, K.G.: Equilibrium Test A Method for Closure Pressure Determination, paper SPE/ISRM 78173, SPE/ISRM Rock Mechanics Conference, Irving, Texas, Oct.20-23, 2002.

4. Castillo, J.L.: Modified Fracture Pressure Decline Analysis Including Pressure-Dependent Leakoff, paper SPE 16417, SPE/DOE Low Permeability Reservoirs Symposium, Denver, Colorado, May 18-19, 1987.

5. Hillis, R.R. and Reynolds, S.D.: The Australian Stress Map, Journal of the Geological Society of London 157, pp.129-149, 2000.

6. Zoback, M. D., D. Moos, L. Mastin, and R. N. Anderson,. Wellbore breakouts and in-situ stress, J. Geophys. Res., 90, pp. 5,5235,530, 1985.

7. Cornell Fracture Group (http://www.cfg.cornell.edu/software/software_policy.htm)

8. Hossain, M.M., Rahman, M.K. and Rahman, S.S.: Hydraulic Fracture Initiation and Propagation: Roles of Wellbore Trajectory, Perforation and Stress Regimes, Journal of Petroleum Science & Engineering 27(3-4), pp.129-149, 2000.

9. Mukherjee, H. and Economides, M.J.: A Parametric Comparison of Horizontal and Vertical Well Performance, SPE Formation Evaluation, pp.209-216, June, 1991.

10. Demarchos, A.S., Porcu, M.M. and Economides, M.J.: Transversely Multi-Fractured Horizontal Wells: A Recipe for Success, paper SPE 102263, SPE Russian Oil and Gas Technical Conference and Exhibition, Moscow, Oct.3-6, 2006.

11. Crosby, D.G., Rahman, M.M., Rahman, M.K. and Rahman, S.S.: Single and Multiple Transverse Fracture Initiation from Horizontal Wells, Journal of Petroleum Science and Engineering 35(3-4), pp.191-204, 2002.

12. Rahman, M.M., Hossain, M.M., Crosby, D.G., Rahman, M.K. and Rahman, S.S.: Analytical, Numerical and Experimental Investigations of Transverse Fracture Propagation from Horizontal Wells, Journal of Petroleum Science and Engineering 35(3-4), pp.127-150, 2002.

13. Joshi, S.: Horizontal Well Technology, Penn Well Books, Tulsa, Oklahoma, 1991.

14. Hossain, M.M., Rahman, M.K. and Rahman, S.S., A Shear Dilation Stimulation Model for Production Enhancement from Naturally Fractured Reservoirs, Society of Petroleum Engineers Journal, pp.183-195, June 2002.

15. Mahoney, J.V., Stubbs, P.B., Schwerer, F.C., and Dobscha, F.X.: Effect of a no-proppant foam stimulation treatment on a coal seam degasification borehole, Journal of Petroleum Technology 33, 1981, 2227-2235.

16. Palmer, I.D., Fryar, R.T., Tumino, K.A., and Puri, R.: Comparison Between Gel-Fracture and Water-Fracture Stimulations in Black Warrior Basin, paper SPE 23415 (Unsolicited), Coalbed Methane Symposium, The University of Alabama/Tuscaloosa, May 13-16, 1991.

17. Mayerhofer, M.J., Richardson, M.F., Walker, R.N., Meehan, D.N., Oehler, M.W., and Browning, R.R. Jr.: Proppants? We dont need no proppants, paper SPE 38611, SPE Annual Technical Conference and Exhibition, San Antonio, Texas, Oct. 5-8, 1997.

18. Rahman, M.K. and Joarder, A.H.: Investigating Production-Induced Stress Change at Fracture Tips: Implications for a Novel Hydraulic Fracturing Technique, Journal of Petroleum Science and Engineering 51(3-4), pp.185-196, 2006.

10 SPE 106276

Table 1. Summary of in-situ stress characterization

Table 2. Surface tension and contact angle of linear gel and cross-linked gel fracturing fluids Fluid System Surface

Tension (dyne/cm)

Contact Angle (deg)

Cut surface

Split surface

Gel 56.88 99.1 78.1 Fresh Linear Gel 59.11 85.8 57.8 Fresh Cross-linked Gel

42.63 74.6 60.1

Broken Linear Gel 54.49 86.9 61 Broken Cross-Linked Gel

40.87 87.2 58.7

Well No.

Break-down

pressure (psi)

ISIP (psi)

Closure pressure

(psi)

Reason for uncertainty

Minimum horizontal

stress (psi)

Vertical stress

(psi)

Depth (ft)

1 NA 2738 2643

2691 2508 2277

2 NA 3073 ?-2875 Short tail

? - 2974 2642 2302

3 3200 3185 ?-3125 Short tail

? - 3155 2632 2286

4 2650 2620 2450-

2598 Bleed off 2535 -

2609 2598 2304

5 NA 2846 2580

2713 2672 2290

6 NA 3278 2900

3089 2776 2280

7 NA 2541 2528

2535 2720 2290

8 NA 2964 ?-2875 Short tail

? - 2920 *2436 2288

9 2870 2650 2505

2578 2593 2226

10 NA 3050 2750-

2955 Bleed off 2900 -

3003 2545 2276

11 NA 3349 ?-3190 Short tail

? - 3270 2518 2215

12 NA 2880 2680

2780 2559 2204

13 NA 2715 2655

2685 - 2246

14 2600 1708 1610

1659 2632 2257

15 NA 3927 2970

3449 2840 2326

16 NA 2583 2550

2567 2635 2220

17 2950 3033 2803

2918 *2415 2237

18 NA 2723 2662 2693 2852 2542

19 NA 3295 2845

3070 *2221 2178* Indicates that part of the density log was not available for calculation

and a density of 1 psi/ft was used in the calculation.