spe 64493 ms fracasdfturing peat field bowen basin

8/16/2019 SPE 64493 MS Fracasdfturing Peat Field Bowen Basin

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SPE 64493

Keys to the Successful Application of Hydraulic Fracturing in an Emerging CoalbedMethane Prospect - An Example from the Peat Coals of AustraliaM. Badri, SPE, Halliburton Australia Pty Ltd; D. Dare, SPE and J. Rodda, SPE, Oil Company of Australia; G. Thiesfield,SPE, Halliburton Australia Pty Ltd and M. Blauch, SPE, Halliburton Energy Services, Inc.

Copyright 2000, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the SPE Asia Pacific Oil and Gas Conference and

Exhibition held in Brisbane, Australia, 16–18 October 2000.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection 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 atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; 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.

AbstractEarly stimulation work in Peat Field of Queensland, Australiainvolved application of cavity completion techniques to produce methane gas at commercial rates in the first wells

completed in the reservoir gas cap. Early in the project life,cavity completion treatments resulted in promising andacceptable gas flow rates. However, excessive cost associatedwith this technique led to consideration of alternate

stimulation approaches by the design team. The mainobjective was to achieve similar or better gas rates at thelowest cost.

Multi-seam nitrogen-foam stimulation was conducted inseveral wells of the Peat field to assess the effectiveness of

this technique in terms of: (1) production enhancement andcost reduction; (2) location of the coal-seam intervals in thegas cap (i..e. gas-saturated coals) and; (3) improved

completion efficiency.To minimise the effects of tortuosity and multiple far-field

fractures in addition to ensuring that each coal-seam interval

received adequate treatment, a staged stimulation approach incombination with other remedies such as sand slugs and highinjection rates was adopted and successfully applied.

Zonal Isolation was achieved through the use of the newlydeveloped, easily drillable composite plugs that allow stagedtreatment with flowback capabilities.

References at the end of the paper.

Field data of representative Peat wells will be used todemonstrate the successful application of the hydraulicfracturing approach that resulted in methane gas rates that

more than compete with the early cavity completion

techniques either from a cost or production improvement pointof view.

The following specifics are addressed in the paper:

• A novel fracture design approach and modeling offracturing treatments that can be of value to a broadaudience of operators and design engineers.

• Real-time fracture stimulation methodology, analysis,and execution.

• Remedies to minimize the near-wellbore tortuosityand multiple far field fractures to avoid premature

“screenout” and carry the fracture treatment tocompletion.

• Chemical optimization of fracture fluid designed

based on coal characteristics.• Use of newly developed composite epoxy-glass

fracture and bridge plugs that provide a more efficient

and cost effective way to carry out staged stimulationtreatments.

• Post-fracture production tests to estimate the nitrogen-foam fracture treatment effectiveness in multi-seamCBM wells.

IntroductionThe Peat field1 is located on the eastern edge of the BowenBasin about 20 km east of the town of Wandoan (Fig. 1). Thefield is approximately 8 km wide and 26 km long and

comprises Late Permian Baralaba Coal Measures overlyingthe Burunga Anticline, the largest anticlinal feature in theBowen Basin. Aggregate net coal thicknesses range fromabout 7.1 m to 22.7 m over an interval of between 100 m to

140 m. Individual seam thicknesses range up to 13.7 m. Coaldepths range from 600 m below ground and are currently being investigated to as deep as 1200 m. Within 15 km to the

west coal depths reach over 2000 m.The field is distinguished by its complex nature

1,2. The

northern culmination contains structurally trapped gas withinthe fracture network, whilst the coals on the southern


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2 M. BADRI, D. DARE, J. RODDA, G. THIESFIELD, M. BLAUCH SPE 64493

culmination subcrop an aquifer due to erosion by the overlyingEarly Jurassic Precipice Sandstone. Drilling and completionstrategies are further complicated by the presence of smectite

and illite clays in the interseam sandstones and numerous thinvolcanic tuff beds immediately below the main (basal)Baralaba coal seam. The field was discovered in 1994 after

drilling the Peat -1 core well following a number of olderwells targeting the deep Camboon Volcanics fracture play

which recorded positive gas indications in the Baralaba CoalMeasures. Initial drilling concentrated on the gas cap area withair or air-mist drilling and bare-foot completions being the preferred technique. Many of the wells recorded significant

drilling problems and were either plugged and abandoned orswitched to a mud drilling system.

Following an extensive overview of the previous

operations an integrated appraisal strategy was developed withstaged drilling programs designed to sequentially addressspecific objectives designed to assess the drilling, stimulationand completion techniques for the gas cap area, to identify the

fluid limit for the gas cap and whether a gas cap existed on thesouthern culmination. The gas cap was shown to bestructurally confined and restricted to the northernculmination1 (Fig. 1). In the gas cap area cavitation resulted inflow rates of up to 2.5 MMscfd per well with no major drilling

problems encountered.A review of some of the cavity completion jobs indicated

that though the production improvement was acceptable, it

was mainly due to the creation of tensile fractures in certaincases.

In order to reduce completion times, the design teamdecided to implement high rate nitrogen foam fracturetreatments in the gas saturated gas cap wells to reduce cost and

achieve acceptable production performance.A total of five Peat wells located in the gas cap were

stimulated in two campaigns to minimize the delivery time

and hence the cost given the complicated logistics for a large program in a remote location. The wells were then put on production. The design team reviewed the delivery of servicesand field implementation processes with the goal of improving

on past practices by implementing changes that either result in better production rates or cost saving before the next batch of

wells were stimulated.Staged fracture designs of the targeted Baralaba coal seams

in each of the wells were made using a Real Time 3D fracture

simulator 20

with input of average properties of the coal

intervals combined with previous experience in modeling offracture treatments in offset wells.

Zone isolation was done through the use of the newlydeveloped composite fracture

12 and bridge plugs

13.

Real time data analysis was used to identify remedial procedures for fracture entry problems, or make the changesrequired on the fly to pump the job to completion that wouldresult in an effective stimulation treatment of the coal seam of

interest.Following the high rate nitrogen foam fracture jobs the

wells were production tested to evaluate the effectiveness of

the treatments and to formulate a strategy to reduce cost andimprove production through change in the job design,implementation, and delivery of services.

Coal DescriptionThe Peat-1 well core data provided the following information2

on the Baralaba and Kaloola coals of the Peat wells. The coals present in the wells can be divided into two Late Permian unitsstratigraphically, the Baralaba Coal Measures which

conformable overlies the Kaloola Member. The Baralaba CoalMeasures consists of up to six thick, relatively clean seams(between 0.4 and 8.1 m thick) and are predominantly dull

clarain to clarain (Dmb to Db). They are interbedded withsandstones and siltstones. Bright bands typically comprise 30 -40% of these coals. Cleat is often unmineralized and open

fractures are evident in a number of seams.Gas content for these coals varies between 7.52 and 10.60

m³/tonne (DAF basis) with relative densities between 1.28 and1.41 g/cc. Gas composition is variable with methane content

ranging between 81.3% and 98.7%. Vitrinite reflectanceranges from 0.6 to 0.65 and proximate analysis has shownthese coals to have 4.9 to 17.6% ash, 6.6 to 9.1% moisture and29.1 to 31.4% volatile matter. The coals are in the high

volatile bituminous C range.

Example Wells - Fracture stimulation methodology,analysis, and executionDue to the number of fracture stimulation jobs and thelogistics involved mainly the liquid nitrogen deliveryschedules, the wells were treated in batch of three tomaximize the utilization of resources, save on cost by areduction in the service delivery time and more importantly to

complete the jobs safely.A parallel approach was taken whereby an exploration and

a development program were run concurrently. A stop gap

between stimulation campaigns was scheduled to evaluateresults of the treatments before completing subsequentlyscheduled wells to improve on what was practiced in the

previous ones, and introduce any changes to the programs orutilise new technologies that would help achieve better gasdeliverabilities at a lower operating cost.

Three typical Peat gas cap wells (Peat A, B, and C) wereselected to demonstrate the application of the high ratenitrogen foam treatments to successfully enhance the gas

production of the Baralaba coal intervals. To reduce the

fluctuations in the surface pressures, the constant internal phase design proposed by Harris23 was used. The surface pressures were converted to bottomhole pressures as

demonstrated by Harris

& Pippin24

for treatments in theFruitland coals wells. The converted bottomhole pressuresalong with reservoir, fracture fluid properties and treatmentdata were used for the analysis of the pre-fracture diagnostictests to estimate the stress level, leak-off characteristic, and the

friction contribution from the perforations and near well-boretortuosity. The results from the pre-fracture diagnostic tests


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KEYS TO THE SUCCESSFUL APPLICATION OF HYDRAULIC FRACTURINGSPE 64493 IN AN EMERGING COALBED METHANE PROSPECT 3

along with the Nitrogen foam properties were used as input ina 3-D fracture simulator

20 to infer the fracture geometry.

Peat well A, B, and C were drilled in October 1998 as

appraisal wells in the gas cap of Peat Field (Fig. 1) to assessthe lateral productivity of the coal seams of the Baralaba coalmeasure across the gas cap. The wells were mud drilled to TD,

logged and cased without testing.The stimulation program was designed to hydraulically

fracture the Baralaba coal intervals to evaluate their productive

capacity in each of the subject Peat wells. Given the thicknessof the different intervals and to ensure that each of theBaralaba coal seams received adequate stimulation, the zones

were fractured individually to achieve good proppant placement within each target horizon. A typical treatmentschedule for a Peat Well is shown in Table 2.

The bottom coal interval was perforated using 3.5” guns at5 shots per foot and 60

o phasing, then hydraulically fractured

pumping down the 5 ½” casing. The next coal seam up was

then perforated, and the new composite frac-plug12

was run

using wireline and set above the bottom zone to isolate it fromthe next one up. The second coal interval was stimulated and

the completion process repeated for the rest of the intervals inthe well.

Composite bridge plugs13 were at times run to isolate

intervals with low pressure to minimize the risk of guns beingstuck in the hole.

A composite bridge plug was run above the top mostinterval once all the seams in a well were treated to isolate the batch of wells in order to move in and rig up the workover rig.

Given the location of the coal seams in the gas cap, a 70%

quality nitrogen foam fluid was used to stimulate all theintervals in Peat wells. This fluid type was selected to

minimize the liquid retention in the seams which affect thecleats relative permeability to gas as well as any soprtionswelling of the coal when gelled fluids are used

6.

Local Australian 16/30 mesh API sand with conductivities

close to Ottawa sand was used in all the sand slugs and mainfracture stimulation jobs since it was readily available at acheaper price than the imported sand, thus minimising cost.

The stimulation treatment of each of the coal seamintervals involved the following stages in the order ofexecution: 1) Performing a small injectivity breakdown test, 2)

Carrying out a Stepdown test 3) Pumping of sand slugsfollowed by 4) Implementing the main nitrogen foam fracturetreatment.

Multiple Stage FracturingMultiple coal intervals can be fractured using different

techniques such as: 1) Ball & Baffles, 2) Bridge Plugs andPackers, 3) Sand Plugs, 4) Limited Entry, 5) Restricted Accessand 6) Interseam Access.

Up to three (3) coal seam intervals were targeted for astaged nitrogen-foam stimulation in each of the Peat well A,B, and C. Due to the distance between the targeted coal

intervals, and not knowing before-hand the tortuosityrestrictions, stress magnitude and levels in each of the zone,

the design team decided to isolate and fracture stimulate eachof the intervals separately to ensure that each horizon receivedadequate stimulation. Moreover the design team wanted to

minimize the drill out time and complete the wells in a short period of time to avoid fluid loss into the coal seams/fracpacksfor better production enhancement.

Zone isolation of the the coal seam intervals X1, X2, andX3 in each of the Peat Wells was achieved through the use ofthe newly developed composite epoxy-glass fracture plugs12

since the wells were already cased and cemented before thefracture stimulation program was initiated. The fracture plug ismade of an easily drillable, lightweight composite material

containing no metals allowing staged zonal treatment withflowback capabilities after the fracture stimulation job.

The new composite plug in combination with nitrogen-foam stimulation improves completion efficiency and greatlyreduces the potential for downhole tool problems, includingwellbore debris in addition to the reduced drilling time and

difficulties of drilling or retrieving tools that may be

experienced with the use of cast iron plugs. Guoynes et al12 presented a summary of more than 100 wells that were

completed using the composite plugs.After the zones were treated, the well was flowed back,

allowing closure of the fractures and enhancing wellbore

clean-up.In few instances, sand plugs were used instead of the

fracture plugs in the case of proppant left in the hole due tounder-displacment of the fracturing fluid covering the planned plug casing seat.

After the last coal seam zone was fractured, a composite

bridge plug13

was run to isloate the wellbore. This reduced rigstandby time, allowing several wells to be treated before

mobilisation of the workover rig. The workover rig was thenmoved to drill-out the plugs, clean-out the hole and runcompletion.

The same bit was used to drill-out all the plugs in each of

the well without any operational problems or safety concerns.This approach has resulted in a rig time saving of 4 hours perwell, and has allowed the Operator to achieve wellstream

production 27 days sooner than with either the use of cast iron plugs, or the cavity completion approach.

Fracture Fluid SelectionIn coal reservoirs, the interaction of the coal with stimulationfluids is a critical design factor which is often under-

emphasized. Bowen basin coals10 in general, exhibit a uniqueset of microlithotype, tectonic, cleat and mineralizationcharacteristics which require specific design consideration. A

well-engineered stimulation treatment requires the chemicaloptimization of the fracture fluid based on coal characteristicsand settings.

Given the location of the gas saturated target coal intervalsin the gas cap of the subject Peat wells, procedures were planned to minimize the introduction of liquids into the coal

cleats. This objective could be accomplished by the use of anitrogen foamed fracture fluid.


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Nitrogen foam with minimal surfactant loading and gelcontent could achieve the required foam rheology underdownhole treating conditions. Because of the high free gas

content of the these coals, the higher gas content of a nitrogenfoam treatment fluid could help minimize potentialdetrimental aqueous fluid saturation and relative permeability

effects in addition to enhancing methane desorption. Anadditional incentive for a foamed system resulted from the

fluid efficiency afforded by a foam fluid. The high efficiencyfluid was strongly recommended based on the estimatedmoderate permeability coupled with the pressure dependentleak-off of the coal intervals considered for stimulation. The

lower leak-off of the nitrogen foam fluid helped ensure thatthe minimum fluid requirement needed to create the fracturegeometry to improve the gas production.

Treated water with a base salt concentration of 2% potassium chloride (KCl) was used to minimize claydispersion related to ionic depletion. The 2% KCl treatedwater was used to determine injection pressures, and stress

magnitude, as well as estimate the tortuosity effects throughthe use of Stepdown Rate Tests

23 (SDRT). This fluid was also

used to carry the proppant during the sand slug stage3,5

which preceded the main fracture treatments.

The pH of the pumped fluids was buffered to the range of

the 4 to 5 to reduce precipitation of potential carbonate scalesand to assist in gel clean-up

10.

To minimize fluid retention, and contact with the coal over

time, well clean up of all the treated intervals was conducted atnight time following the treatment under controlled flow-backuntil the pressure was dissipated prior to running thecomposite bridge plug to isolate each well.

Near Wellbore Tortuosity and Far Field Multiplefractures

The creation of multiple fractures in coal seams followinghydraulic fracture treatments has been documented by several

authors through laboratory and mineback experiments ofhydraulic fracture jobs of different types and sizes in bothAustralia15,16 and the USA17.

As observed by Jeffrey et al15

through mineback of smallscale experiments at the German Creek Mine, multiple

fractures with horizontal and vertical components, as well asorthogonal, asymmetrical and sub-parallel far field fracturesare created. It was also observed16 that fractures can be

affected by pre-existing joints and cleat fractures in the coal.

Tortuosity is described as the complex and the restrictive path through which fluid must travel from the wellbore to the

main body of the fracture(s). The path is made complex by acombination of turning and multiple fractures. The complex branched geometries result in reduced width fractures whichgive rise to high net fracture pressures, and an increased riskof premature “screen-out” or short propped fracture if the jobis pumped to completion. A conceptual model depicting the

near wellbore restrictions and modelling of mutiple fractures isshown in Fig. 2.

To minimise the effects of near wellbore tortuosity, severalapproaches have being attempted by different parties

3,4,5,7,8,9.

The proposed techniques ranged from the use of high energy

stimulation8 to cutting slots

7 in the coal in the direction

perpendicular to the horizontal minimum stress to initiate thefracture in the preferred propogation plane. The creation of

slots in the casing opposite the coal interval is done using jetnozzles in combination with a compass. Cutting slots in thecasing has worked well in some of the early wells located in

the northern part of the Bowen Basin. However due to the costassociated with this technique, the design team decided to lookat other approaches instead.

A second approach was through the use of perforationtechniques as described by Stadulis

9 for a pre-completion

consideration in which multiple fractures are anticipated.

However, due to a lack of information regarding the stressdirection and existence of weak fracture planes such as naturalfractures/joints, the design team decided to pursue a cheaperand less complicated means of reducing the near wellbore

tortuosity such as using gel4,5

or sand slugs3,5

. Gel slugs werenot considered due to the possible reduction in permeabilitycaused by sorption induced swelling of the coal matrix whenin contact with gelled fluid in addition to gel plugging ofcleats6.

Though sand slugs were not always successful in reducingthe tortuosity effects as discussed for the typical Peat wellstreated in this paper, they were deemed to be the most

appropriate approach due to the cost and operational ease ofimplementation.

Consequently all the main treatments were preceded by pumping sand slugs for the purpose of minimizing the effectsof near wellbore tortuosity. This was not only to avoid

premature “screenout” and carry the fracture treatment tocompletion but also to create deeply penetrating fractures thatare required for a proper production enhancement given the

moderate to low permeability of the targeted coals intervals inthe subject wells.

The effect of multiple fractures was minimized11 by 1)reducing the perforated length, 2) use of high rate high

injection rates, 3) high fluid viscosity such as nitrogen foams,4) implementation of the sand slugs, or minimizing the

number of perforations.

Pre-Fracture Diagnostic TestsPre-fracture diagnostic tests involve the performance of

small size Injection/Breakdown, Step-Down Rate Test(SDRT) and minifrac tests as well as the pumping of sand or

“feeler” slugs for the purpose of acquiring data to use in a 3Dsimulator to evaluate the fracture propagation model, and toestimate the fracture half-length and conductivity.

The pre-fracture test designs were based on pastexperience in stimulating wells in the area. No mini-frac testswere planned for the proposed wells unless pre-fracture

diagnostic tests dictates a modified approach to the oneapplied in offset wells. To ensure that the proposed treatmentswould behave as predicted, or close to the ones from offset


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wells, diagnostic tests such as Injection/Breakdown, Step-Down Rate Tests and the pumping of sand slugs were carriedout on the first wells to estimate the stress level, the leak-off

mechanism and parameters and to identify if any nearwellbore restrictions existed such as friction due to perforationand tortuosity and to quantify these effects.

The G-function derivative approach following a diagnosticinjection test as proposed by Barree and Mukherjee

18 was used

to identify the leak-off type and estimate the closure pressure

for each of the treated coal intervals. The data from the smallInjection/Breakdown tests was used for this purpose sincesubsequent injections of fluids into the coal at times resulted in

an increase of the closure pressure. These effects are caused by changes in the fracture geometry in addition to stressdependent leak-off, the propagation of multiple fractures aslarger fluid volumes are pumped into the coal and the possibility of creating a stress induced damage

27 thus reducing

the permeability of the coal around the fracture plane.

Pressure dependent leak-off behavior was common to most

of the coal seam intervals as shown in Fig. 3, 9, 12, 16, 20, 23,and 26. Pressure dependent leak-off

19 is indicated by the large

“hump” in the superposition derivative (Gdp/dG) that liesabove a line through the normal leak-off data prior tohydraulic fracture closure. Pressure dependent leak-off is a

result of cleats (fractures/fissures) that were dilated by theinjection test. As the pressure declines during the fall-off, thefractures/fissures constrict until closure at the fissure opening pressure.

However the G-function plot for Peat A well seam X2

(Fig. 6) indicated a fracture height recession. This leak-off

mechanism occurs19

when the fracture grows into high stressrelatively impermeable layer(s) adjacent to the permeable

zone. During the shut-in, the fracture begins to close in theimpermeable layer(s) first followed by the permeable interval.

The analysis of the injection tests shows that the ISIP varyfrom 2322 psi for Well Peat B seam X3 (Fig. 20) to 837 psi

for well Peat A seam X3 (Fig. 9) or a fracture gradient of 1.45 psi/ft to 0.87 psi/ft and fracture closure pressure (Pc) rangingfrom 1436 psi to 511 psi or a stress gradient of 1.07 psi/ft to

0.66 psi/ft for the same wells and coal intervals respectively.Analysis of the Step-Down Rate tests carried out in Well

Peat B seam X1 and X2 (Fig. 13, 17) indicate that the friction

pressure contribution due to perforation and tortuosity wasmoderate with a total friction of 402 psi and 389 psirespectively with a 50-50 contribution form each.

The sand slugs though not a cure for all was pumped at aconcentration of 1 ppg for all the treated intervals and showedthat it can help reduce the friction pressure contribution due to

tortuosity (Fig. 7 and 21) in some cases and in others nonoticeable difference was indicated (Fig. 4, 10). However thisdoes not mean that higher sand concentration if used duringthe sand slug stage would not have worked and since thefriction due to tortosity in most cases was low to moderate noattempt was made to pump a second sand slug with an

increased sand concentration. The second goal of the sand slug

was also to help fluid diversion into most perforations in along perforated interval.

No mini-fracture tests were carried out in order to perform

the maximum number of fracture treatments to save on theservice delivery time and cost of the jobs. The results of the pre-fracture diagnostic tests using in house interpretation

software programs along with feedback from actual treatments provided a basis for the use of a 3D fracture simulator

20 to

infer fracture growth behavior and estimate fracture

dimensions. However due to the complex process involvedwhen hydraulically fracturing coal seams, we relied heavily onengineering judgement and local experience in the area in

either modifying the pumping schedule on the fly or carryingthe jobs to completion for the few cases that deviated from thenorm.

Net Pressure Analysis and MethodologyThe high net fracture pressure in coal seams is caused by the

development of complex multiple fractures3,11

, “tip effects”26

,

near-wellbore tortuosity3, pressure dependent leakoff 18, andthe perforation density and phasing9,11 which may act as

fracture initiation sites when the difference between thehorizontal principal stresses is small.

The consequence of these affects11 is the risk of premature

“screen out”, the creation of reduce fracture length, and high proppant conductivity near the wellbore if the job is pumpedto completion.

Due the coal being a soft medium in addition to theexistence of weaknesses such as cleats and joints, and tomodel its nonlinear behavior, a 3D fracture simulator 20 was

used to infer the fracture propagation behavior and estimatethe created fracture half-length and conductivity. The fracture

parameters are then converted into an equivalent skin factorthat is used as one of the input parameters in a reservoirsimulator for production forecast and well spacing purposes.

The methodology that was followed in the analysis of the

net pressures is discussed next.Following the analysis of the pre-fracture diagnostic tests

(Figs. 3, 6, 9, 12, 16, 20, 23 and 26), the stress results are used

in a 3D fracture simulator to history match the net pressures ofthese tests. The total friction exponent, the perforation andnear-wellbore friction multipliers are estimated using the Step

Down Rate Test23

. Modeling of the net pressures is done byincorporating the results of the step-down rate test and varyingthe values of the stresses of the bounding layers, and the leak-

off coefficient(s) till the actual net pressures (Observed Net)are close to the modeled ones (Model Net). The pressurehistory matching focuses on the fall-off period since the

difference between the net pressures (observed versusmodeled) for the injection phase is due to friction fromtubulars, perforations, tortuosity, multiple fractures or a

combination of all these effects.The parameters derived from the simulation of the pre-

fracture data such as , friction parameters, stresses and leak-off

coefficient are then used to history match the main fracturetreatment pressures by using the rheological properties of the


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nitrogen foam frac fluid and by varying the number and timingof the of multiple fractures till the observed net is close to themodeled one (Fig. 5, 8, 11, 15, 19, 22, 25, 28, and 30).

Modeling of the net pressure using single-planar fracturesresulted in lower net pressures than observed and a fracturehalf-length that is 3 to 4 times the one estimated from the post

fracture production tests. We have also tried to model the highnet pressure increase for the few cases treated in this paper by

using high fracture modulus to account for “fracture tipeffects”. This has resulted in very high fracture widths thatwere inconsistent with the few cases where “screenout” (Fig.

19) occurred. Consequently we resorted to the use of multiple

fractures to model the high net pressure.This approach was supported by the evidence of the creation

of multiple fractures through mine back experiments 15,16,17 and

the authors experience in the area where substantial decreasein treating pressures of up to 1100 psi following the firststages of the sand laden fluid past a “critical” sandconcentration (Fig. 15). This reduction in treating pressures is

the result of the “screening out” secondary wings of thecreated multiple fractures thus leading to a less complicatedgeometry or tortuous pathway and the pumping of the rest ofthe fluid into the main branch. Another possible cause of thedecrease in treating pressures as discussed by Harris &

Pippen25

is the erosion of perforation tunnels with time caused by the high pumping rates of the nitrogen foam fluid and sand.The effects of perforation erosion may contribute to a certain

degree to the decrease in the net pressures, but we believe thatshutting off secondary fractures is a more possible cause.More importantly the results of the post-fracture productiontests suggest that the resulting fracture(s) following atreatment will be shorter and wider. The net pressure increase

may be the due to the existence of multiple fractures and “tipeffects” to a certain extent since these appear to be present inalmost all reservoirs. The results of the net pressure analysis

are summarized in Table 3.

Post-treatment Production TestsAn extended post-fracture production and pressure buildup

survey was conducted to evaluate the effectiveness of thestimulation treatments in enhancing the production of the

selected wells and to formulate a strategy for the completionof future wells in order to maximize production and or reducecost.

Production Logs were run on Peat Wells A, B, and C to

evaluate the flow contribution from the coal seams that werehydraulically fractured in each of the wells. The gas flow,

water rate and surface pressures were monitored using asurface separator. Downhole gauges were run to monitor flowand build-up pressures which in combination with the flow

rates were used in well tests interpretations to estimate thereservoir properties.

The lack of stabilization of the pressure derivative made

the well test interpretation difficult. This ambiguity wouldhave been eliminated if pre-fracture tests were conductedwhere the effective permeability to gas estimates from the pre-

fracture tests would have been used to estimate the effectivefracture conductivity and half-length from the post-fracturedata.

The well test interpretation using coal gas well testtechnology

21 was conducted to estimate the reservoir

properties. The analysis and simulation methodology resulted

in an estimate of the parameters listed in Table 1.The log-log and Horner match of the buildup period for

Peat Well A, B, C are shown in (Fig. 31 - 36). Results of the

test interpretation as reported in Table 1 show a higly negativeskin, indicating the creation of very efficient fractures and thatthe three wells were successfully stimulated.

ConclusionThe use of composite plugs resulted in a safe, more efficient

and cost effective way to carry out staged nitrogen foamtreatments and complete and produce the wells in record time.Up to two foam fracture treatments were carried out per daydespite the limited nitrogen supply through the use of this

stimulation approach thus minimizing the service delivery andworkover time, and hence lowering the cost of each wellcompletion.

Past experience in the Peat area coupled with the proper

fracturing fluids selection, the use of real time fractureanalysis and process improvement led to a very successfulstimulation campaign in achieving good gas production ratesat a reduced cost. Analysis of the pre-fracture

injection/breakdown tests using the G-function derivativeapproach helped identify the leakoff mechanism and estimatethe closure pressure of each coal interval. The net pressurehistory match of the treatment data is achieved through the useof mutiple fractures in a 3D fracture simulator for most cases

based on evidence from mineback experiments though “tipeffects” may contribute to the increased net pressures to acertain extent.

The decrease in treating pressures past a “critical” sandconcentration when pumping sand laden fluids is believed to be due to “screenout” of secondary fracture branches and to

certain extent caused by the erosion of perforation tunnelswith time.

More importantly this approach has resulted in a technique

that more than competes with the cavity completion that wascarried out on earlier wells in this field either in terms of production enhancement or completion cost.

The high rate nitrogen foam fractures also resulted in the

successful creation of efficient propped fractures that gaverise to the excellent production for the different wells treated.

Moreover the success of the stimulation treatments wasconfirmed by the post-fracture production tests carried out onthe selected Peat wells that showed a high negative skin.

The high rate nitrogen foam fracturing of the Peat Wellsresulted in methane production rates of up to 5 MMscfd.

AcknowledgementsThe authors would like to thank the respective management ofHalliburton and Oil Company of Australia, for the opportunity


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to present this work. Special thanks are due to Ashley Edgarfor his contribution to the discussion on Peat coal geology. Wewould like to acknowledge the efforts of all the OCA and

Halliburton personnel who participated in this project andcontributed to the success of the different campaigns and madeit fun to work with.

References1. Dare, D.L., Edgar A.V. and O'Neill, P.J.: “An integrated

Appraisal Strategy for the Peat Coal Seam Methane Resource,”Abstract, presented at the 1998 International Conference on

Coal Seam Gas and Oil, Brisbane, Australia March 23-24.

2. Edgar A. V. Private Communication, 18 May 2000.3. Cleary, M.P., Johnson, D.E. Kogsboll, H.H., Perry, K. F., de

Pater, C. J., Stachel, A.,Schmidt, H., and Tambimi, M.: “FieldImplementation of Proppant Slugs to avoid Premature Screenout

of Hydraulic Fractures with Adequate Proppant Concentration,”SPE paper 25892 presented at the 1993 Rocky MountainRegional Meeting and Low-Permeability Reservoir Symposium,26-28 April.

4. Aud, W.W., Wright, T.B., Cipolla, C.L., and Harkrider, J.D.:“The effect of Viscosity on Near-Wellbore Tortuosity and

Premature Screenouts,” paper SPE 28492 presented at the 1994SPE Annual Technical Conference and Exhibition, NewOrleans, 25-28 September.

5. Kilstrom, K., Gijtenbeek, K.V., and Palmer, I.: “Minimizing

Multiple fractures in Coalbed Methane Fracturing operations,” paper SPE 38859 presented at the 1997 Annual Technical

Conference and Exhibition, San Antonio, TX, 5-8 October.6. Puri, R., King, G. E., and Palmer, I. D.:“Damage to Coal

Permeability During Hydraulic Fracturing,” Paper SPE 21813

presented at the 1991 Joint Rocky Mountain Regional Meetingand Low Permeability Syposium, Denver, CO, April 15-17.

7. Surjaatmadja, J.B., Abbas, H.H., and Brumley, J.L.: “Elimination of Near-Wellbore Tortuosities by Means ofhydrojetting,” SPE 28761, Presented at the 1994 Asia Pacific

Oil & Gas Conference, Melbourne, Australia, Nov. 7-10.

8. Snider, P.M., Hall, F.R., and Whisonant, R.J.: “Experienceswith High Energy Stimulations for Enhancing Near-WellboreConductivity,” paper SPE 35321 presented at the 1996 SPEInternational Petroleum Conference and Exhibition of Mexico,

Villahermosa, Mexico, 5-7 March.9. Stadulis, J. M.: “Development of a Completion Design to

Control Screenouts Caused by Mutiple Near-WellboreFractures,” paper SPE 30503 presented at the 1995 Rocky

Mountain Regional/Low-Permeability Symposium and

Exhibition, Denver, Colorado, Mar. 19-22.10. Blauch M. Private Communication, May 1998.11. Lehman, L.V. and Brumley, J.L.: “Ethiology of Multiple

Multiple Fractures,” SPE paper 37406, presented at the 1997SPE Production Operations Symposium, Oklahoma City, OK,

March 9-11.12. Guoynes, J., Kozera, G., Waddell, M., Toothman, R., Albert, R.,

Franklin, K.: “Non-metallic Frac Plug in Coalbed Applications,”SPE paper 51053, Presented at the 1998 Eastern RegionalMeeting, Pittsburg, Pennsylvania, Nov. 8-11.

13. Savage, R. and Fowler, H.: “ Taking New Materials Downhole –The Composite Bridge Plug,” paper presented at the 6th Annual

International Conference on Horizontal Well Technology –Multilaterals, Underbalanced Drilling and EmergingTechnology Conference, PNEC, Houston, TX, Oct. 24-26, 1994.

14. Coalbed Methane Technology, Halliburton Energy Services,

Inc., (1991) 12.

15. Jeffrey, R.G., Enever, J. R., Phillips, R., Moelle, D., andDavidson, S.: “Hydraulic Fracturing experiments in VerticalBoreholes in the German Creek Coal Seam,” paper presented atthe 1992 Coalbed Methane Symposium, Townsville, QLD 19-

21 November.16. Jeffrey, R.G., Weber, C.R., Vlahovic, W., and Doyle, R.P.:

“Propped Fracture Geometry of Three Hydraulic Fractures inSydney Basin Coal Seams,” paper SPE 50061 presented at the

1998 SPE Asia Pacific Oil & Gas Conference, Perth, Australia, Nov. 7-10.

17. Diamond, W.P. and Oyler, D.C.: “Effects of StimulationTreatments on Coalbeds and Surrounding Strata-Evidence FromUnderground Observations,” Bureau of Mines RI 9083, 1987.

18. Barree, R.D. and Mukherjee, H.: “Determination of Pressure

Dependent Leakoff and Its Effect on Fracture Geometry,” paperSPE 36424 presented at the 1996 SPE Annual Technical

Conference and Exhibition, Denver, CO, Oct. 6-9.

19. Craig, D.P, Eberhard, M. J., and Barree, R. D.: “Adapting HighPermeability Leakoff Analysis to Low Permeability Sands for

Estimating Reservoir Engineering,” paper SPE 60291 presentedat the 2000 Rocky Mountain Regional Meeting/LowPermeability Reservoir Symposium, Denver, CO. 12-15 March.

20. FracproPT Version 9.0 User’s Manual, Pinnacle Technologies,Inc, 1998

21. Mavor, M. J.: “Peat Wells - Post-Fracture Well TestInterpretation” Internal Report prepared for Oil Company of

Australia, 7 September 1999.22. Weijers, L., Cipolla, C. L., Byrd, A. C., and Kunzi, R.:

“Implementation of Real-Data Fracture Analysis MethodologyImproves Treatment Success,” GasTIPS 45, a GRI publication,Spring 1997.

23. Wright, C. A.: “On-Site, Stepdown Test Analysis DiagnosesProblems and Improves Fracture Treatment Success,” Petroleum

Engineer International, January 1997, p. 51-63.

24. Harris, P. C., Klebenow, D. E., and Kundert, D. P.: “ConstantInternal Phase Improves Stimulation Results,” SPE paper 17532 presented at 1988 Rocky Mountain Regional Meeting, Casper,WY, May 11-13.

25. Harris, P. C., and Pippin, P. M.: “High Rate Foam Fracturing:

Fluid Friction and Perforation Erosion,” SPE Production &Facilities Journal, February 2000.

26. Jeffrey, R.G.: “The combined Effect of Fluid Lag and Fracture

Toughness on Hydraulic Fracture Propagation,” SPE paper

18957 presented at the 1989 Rocky Mountain RegionalMeeting/Low-Permeability Reservoir Symposium, Denver, CO.

27. Palmer, I.D.: “Induced Stresses Due to propped HydraulicFracture in Coalbed Methane Wells,” paper 25861 presented atthe 1993 SPE Rocky Mountain/Low Permeability Reservoirs

Symposium, Denver, Colorado, 12-12 April.


8/15


Table 1. Well Test Analysis Results

Table 2. Treatment Data Summary – Peat Well B

Table 3. Net Pressure Treatment Analysis Results


9/15


Fig.1 Map of the Peat Field indicating the gas cap, QLD, Australia


10/15


Fig. 2 Modeling of multiple hydraulic fracture

growth using “equivalent” fractures

Fig. 3 Peat A, X1 : G-Function plot indicatingpressure dependent leakoff

Time (mins)

Net Pressure (psi) Observed Net (psi)Btm Prop Conc (ppg)

Slurry Flow Rate (bpm)

36.90 42.90 48.90 54.90 60.90 66.90 0

400

800

1200

1600

2000

0

400

800

1200

1600

2000

0.000

0.800

1.600

2.400

3.200

4.000

0.00

8.00

16.00

24.00

32.00

40.00

Surf Press [Csg] (psi)

0

480

960

1440

1920

2400

Net Pressure (psi)Surf Press [Csg] (psi)

0

480

960

1440

1920

2400


0

400

800

1200

1600

2000

Fig. 4 Peat A, X1 : Injectivity and Sand Slug diagnostic testing

Time (mins)

Observed Net (psi)BH Inject Rate

Btm Prop Conc (ppg)

24.90 37.50 50.10 62.70 75.30 87.90 0

300

600

900

1200

1500

0

300

600

900

1200

1500

0.00

8.00

16.00

24.00

32.00

40.00

0.00

2.00

4.00

6.00

8.00

10.00

Fig. 5 Peat A, X1 : 70% Nitrogen Foam Fracture Stimulation

Fig. 6 Peat A, X2 : G-Function plot indicatingHeight Recession during Shut-In

Time (mins)

Net Pressure (psi) Observed Net (psi)Slurry Flow Rate (bpm)

Btm Prop Conc (ppg)

11.90 17.90 23.90 29.90 35.90 41.90 0

240

480

720

960

1200

0

240

480

720

960

1200

0.00

8.00

16.00

24.00

32.00

40.00

0.000

1.000

2.000

3.000

4.000

5.000

Fig.7 Peat A, X2 : Injectivity and Sand Slug diagnostic testing


11/15


Time (mins)

Net Pressure (psi) Observed Net (psi)BH Inject Rate

Btm Prop Conc (ppg)

2.90 16.30 29.70 43.10 56.50 69.90 0

300

600

900

1200

1500

0

300

600

900

1200

1500

0.00

10.00

20.00

30.00

40.00

50.00

0.000

0.800

1.600

2.400

3.200

4.000


0

1200

2400

3600

4800

6000


0

440

880

1320

1760

2200


0

1200

2400

3600

4800

6000

Fig. 8 Peat A, X2 : 70% Nitrogen Foam Fracture Stimulation

Fig. 9 Peat A, X3 : G-Function plot indicatingpressure dependent leakoff

Time (mins)


Btm Prop Conc (ppg)

17.90 23.30 28.70 34.10 39.50 44.90 0

300

600

900

1200

1500

0

300

600

900

1200

1500

0.00

8.00

16.00

24.00

32.00

40.00

0.000

0.800

1.600

2.400

3.200

4.000

Fig. 10 Peat A, X3 : Sand Slug diagnostic testing

Time (mins)


Proppant Conc (ppg)

0.00 5.38 10.76 16.14 21.52 26.90 0

600

1200

1800

2400

3000

0

600

1200

1800

2400

3000

0.00

10.00

20.00

30.00

40.00

50.00

0.00

2.80

5.60

8.40

11.20

14.00

Fig. 11 Peat A, X3 : 2% KCl Water Fracture Stimulation

Fig. 12 Peat B, X1 : G-Function plot indicatingpressure dependent leakoff

Pumping Rate (bpm)

Observed Fric B=0.98 (psi) Est. NWB Friction (psi)Est. Perf Friction (psi)

0 .00 6.00 12.00 18.00 24.00 30.00 0.0

100.0

200.0

300.0

400.0

500.0

0.0

160.0

320.0

480.0

640.0

800.0

0.0

160.0

320.0

480.0

640.0

800.0

Fig. 13 Peat B, X1 : Step Down Analysis indicating NWB and

Perforation excess pressure contributions


12/15


Time (mins)

Net Pressure (psi) Observed Net (psi)Proppant Conc (ppg)


0.00 9.38 18.76 28.14 37.52 46.90 0

600

1200

1800

2400

3000

0

600

1200

1800

2400

3000

0.000

0.200

0.400

0.600

0.800

1.000

0.00

10.00

20.00

30.00

40.00

50.00


0

700

1400

2100

2800

3500


0

1000

2000

3000

4000

5000


0

740

1480

2220

2960

3700


-4

1397

2798

4198

5599

7000

Fig. 14 Peat B, X1: Injectivity, Step Downdiagnostic testing

Time (mins)


Btm Prop Conc (ppg)

0.00 14.98 29.96 44.94 59.92 74.90 0

400

800

1200

1600

2000

0

400

800

1200

1600

2000

0.00

7.00

14.00

21.00

28.00

35.00

0.00

2.80

5.60

8.40

11.20

14.00

Fig. 15 Peat B, X1: 70% Nitrogen Foam Fracture Stimulation


Pumping Rate (bpm)

Observed Fric B=0.83 (psi) Est. NWB Friction (psi)Est. Perf Friction (psi)

0.00 5.00 10.00 15.00 20.00 25.00 0.0

100.0

200.0

300.0

400.0

500.0

0.0

100.0

200.0

300.0

400.0

500.0

0.0

100.0

200.0

300.0

400.0

500.0

Fig. 17 Peat B, X2 : Step Down Analysis indicating NWB andPerforation excess pressure contributions

Time (mins)

Net Pressure (psi) Observed Net (psi)Proppant Conc (ppg)


0.0 22.0 44.0 65.9 87.9 109.9 0

600

1200

1800

2400

3000

0

600

1200

1800

2400

3000

0.000

0.200

0.400

0.600

0.800

1.000

0.00

10.00

20.00

30.00

40.00

50.00

Fig. 18 Peat B, X2 : Injectivity, Step Down Test,Sand Slug

diagnostic testing

Time (mins)


Btm Prop Conc (ppg)

0 .00 11.98 23.96 35.94 47.92 59.90 0

800

1600

2400

3200

4000

0

800

1600

2400

3200

4000

0.00

10.00

20.00

30.00

40.00

50.00

0.00

2.00

4.00

6.00

8.00

10.00

Fig. 19 Peat B, X2 : 70% Nitrogen Foam Fracture Stimulation


13/15



Time (mins)


Proppant Conc (ppg)

41.9 55.5 69.1 82.7 96.3 109.9 0

400

800

1200

1600

2000

0

400

800

1200

1600

2000

0.00

8.00

16.00

24.00

32.00

40.00

0.000

0.800

1.600

2.400

3.200

4.000


0

800

1600

2400

3200

4000


0

800

1600

2400

3200

4000


0

400

800

1200

1600

2000


0

800

1600

2400

3200

4000

Fig. 21 Peat B, X3 : Injectivity, Sand Slug diagnostic testing

Time (mins)


Btm Prop Conc (ppg)

4.90 19.10 33.30 47.50 61.70 75.90 0

400

800

1200

1600

2000

0

400

800

1200

1600

2000

0.00

8.00

16.00

24.00

32.00

40.00

0.00

3.00

6.00

9.00

12.00

15.00

Fig. 22 Peat B, X3 : 70% Nitrogen Foam Fracture Stimulation

Fig. 23 Peat C, X1 : G-Function plot indicatingpressure dependent leakoff

Time (mins)


0.00 4.38 8.76 13.14 17.52 21.90 0

300

600

900

1200

1500

0

300

600

900

1200

1500

0.00

10.00

20.00

30.00

40.00

50.00

Fig. 24 Peat C, X1 : Injectivity diagnostic testing

Time (mins)


Btm Prop Conc (ppg)

0.00 13.98 27.96 41.94 55.92 69.90 0

600

1200

1800

2400

3000

0

600

1200

1800

2400

3000

0.00

10.00

20.00

30.00

40.00

50.00

0.00

2.80

5.60

8.40

11.20

14.00

Fig. 25 Peat C, X1 : 70% Nitrogen Foam Fracture Stimulation


14/15


Fig. 26 Peat C, X2 : G-Function plot indicatingpressure dependent leakoff

Time (mins)

Net Pressure (psi) Observed Net (psi)Btm Prop Conc (ppg)

0 .00 4.18 8.36 12.54 16.72 20.90 0

400

800

1200

1600

2000

0

400

800

1200

1600

2000

0.00

3.00

6.00

9.00

12.00

15.00


0

480

960

1440

1920

2400


0

800

1600

2400

3200

4000


0

600

1200

1800

2400

3000


0

1140

2280

3420

4560

5700


Time (mins)


Btm Prop Conc (ppg)

0.00 14.38 28.76 43.14 57.52 71.90 0

500

1000

1500

2000

2500

0

500

1000

1500

2000

2500

0.00

8.00

16.00

24.00

32.00

40.00

0.00

3.00

6.00

9.00

12.00

15.00


Time (mins)


0.000 1.580 3.160 4.740 6.320 7.900 0

400

800

1200

1600

2000

0

400

800

1200

1600

2000

0.00

8.00

16.00

24.00

32.00

40.00


Time (mins)


Btm Prop Conc (ppg)

0.00 10.98 21.96 32.94 43.92 54.90 0

1000

2000

3000

4000

5000

0

1000

2000

3000

4000

5000

0.00

8.00

16.00

24.00

32.00

40.00

0.00

4.00

8.00

12.00

16.00

20.00



15/15


Fig. 31 Peat A, Log- Log Match Buildup Period

Fig. 33 Peat A, Horner Match Plot – Buildup Period

Fig. 35 Peat B: Log-Log Match Plot – Buildup Period

250

300

350

400

450

500

550

05,00010,00015,00020,00025,000

Superposition Time, Mscf/D

P s e u d o P r e s s u r e , p s i a

Observed Horner data

Simulated Horner data

Test conducted March 1999

kh 71 md-ft

C 0.5 bbl/psi

S -6.6xf 500 feet

Pavg 985 psia

0

1

10

100

1,000

1.00E-04 1.00E-03 1.00E-02 1.00E-01 1.00E+00 1.00E+01 1.00E+02 1.00E+03

Elapsed Time, hours

P r e s s u r e C h a n g e a n d D e r i v a t i v e , p s i

Observed pressure change

Estimated derivative

Simulated pressure change

Simulated derivative

Test conducted March 1999kh 71 md-ft

C 0.5 bbl/psi

S -6.6xf 500 feet

Pavg 985 psia

Fig. 32 Peat B: Horner Match Plot – Buildup Period

0

1

10

100

1,000

1.00E-04 1.00E-03 1.00E-02 1.00E-01 1.00E+00 1.00E+01 1.00E+02 1.00E+03 1.00E+0 4 1.00E+05 1.00E+06

Elapsed Time, hours



Observed Devrivative

Simulated pressure change

Simulated Derivative

kh 11 md-ft

S -7.0

0

50

100

150

200

250

300

350

400

01,0002,0003,0004,0005,0006,0007,0008,0009,00010,000


P s e u d o P r e s s u r e , p s i a

Measured

Simulated

kh 11 md-ft

S -7.0

Fig. 34 Peat C: Log - Log Match Plot – Buildup Period

0

50

100

150

200

250

300

350

400

450

500

02,0004,0006,0008,00010,00012,00014,000


P s e u d o

P r e s s u r e , p s i a

Observed Horner data

Simulated Horner data

0

1

10

100

1,000

1 .0 0E -0 4 1 .0 0E -0 3 1 .0 0E -0 2 1 .0 0E -0 1 1 .0 0E +0 0 1 .0 0E +0 1 1 .0 0E +0 2 1 .0 0E +0 3 1 .0 0E +0 4 1 .0 0E +0 5 1 .0 0E +0 6

Elapsed Time, hours



Estimated derivative

Wellbore storage solution

Wellbore storage solution

Composite Solution

Composite Solution

kh1 176 md-ft

kh2 17.6 md-ft

R1 200 feet

Skin -5.8

Composite Model

Fig. 36 Peat C: Horner Match Plot – Buildup Period

spe 64493 ms fracasdfturing peat field bowen basin

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