Summary After fracture stimulation of a tight gas well, production often rises slowly instead of showing an early transient. This indicates either severe reduction in fracture conductivity or reservoir damage. There is still no agreement in the industry about the most important damage mechanisms. Work performed by Pratts and Holditch in the 1970s showed that fracture-face damage from filtrate invasion is unimportant unless there is permeability damage in the invaded zone of at least 99%. New ideas have been proposed that may better explain the behavior commonly seen in actual tight gas well production data. These ideas include relative permeability with water and gas both immobile at a given saturation ("permeability jail"), small-scale reservoir heterogeneity, and stress-sensitive-matrix permeability at high drawdown. Experience from the field has been contradictory. Sometimes no water is produced back, but gas production does not appear to suffer. In other cases, the gas rate is significantly lower than expected, but significant fracture fluid is recovered. With the inherent coupling of fracture length and permeability in well-test interpretation and the practical impossibility of achieving radial flow in tight-gas reservoirs with large fracture lengths, it has been difficult to prove any theory about the cause of poor performance from tight gas fracture treatments. This paper shows simulation results of a number of damage effects on post-fracture production from an unconventional (0.001-md) gas well. Furthermore, realistic assumptions about proppant-pack cleanup show a connection not only between poor cleanup and short effective fracture length, but also reduction in contacted kh and connected reservoir volume. New reservoir-simulation results are presented that show a 50% reduction of production in the first years because of these effects in unconventional reservoirs.

A B S T R A C TPore pressure and its relationship with fracture net pressure has been reported qualitatively from both field and experimental observations. From a modeling perspective, the ubiquitously used pseudo 3D (P3D) models that are based on linear elastic fracture mechanics (LEFM) do not include the effect of reservoir depletion (or overpressure). Models that utilize effective stress as propagation criteria with a cohesive zone description, introduce the pore pressure directly into the simulation and hence can potentially capture the effect of pore pressure on fracture propagation. This work investigates the effect of pore pressure on hydraulic fracturing net pressure and geometry using empirical and numerical simulation approaches. We carried out an analysis of more than 400 datafrac injections spanning a wide range of geological ages and depositional environments in order to investigate the relationship between observed net pressure and reservoir pore pressure. The net fracture propagation pressure from the fracture treatment analysis was seen to be correlated with the effective stress in the reservoir. Fracture propagation simulations were performed using a coupled finite element -finite difference fracture simulator. The code uses a cohesive zone model (CZM) to describe fracture propagation. Four different effective stress scenarios were used to study the effect of effective stress on net pressure. The simulation results closely match the empirical relation between net pressure and effective stress as obtained from the analysis of actual frac treatment data. It is observed from the simulations that the magnitude of the effective stress also has an effect on the fracture geometry with a high effective stress leading to wider, shorter and more radial fractures. The derived empirical correlation is hence useful as a fracture design parameter. The datafrac net pressure diagnostics workflow in the pseudo 3D models can incorporate local tip pore pressure as a new pressure matching parameter. The pore pressure effect can thus explain high net pressures routinely observed in frac operations and also as a containment mechanism.

After fracture stimulation, production often rises slowly, instead of showing an early transient. This indicates either severe reduction in fracture conductivity or reservoir damage. There is still no agreement in the industry about the most important damage mechanisms. Work done by Pratts and Holditch in the 1970’s showed that fracture face damage from filtrate invasion is unimportant, unless there is permeability damage in the invaded zone of at least 99%. New ideas have been proposed which may better explain the behavior commonly seen in actual production data. These ideas include relative permeability with water and gas both immobile at a given saturation ("permeability jail"), small scale reservoir heterogeneity and stress sensitive matrix permeability at high drawdown. Experience from the field has been contradictory. Sometimes no water is produced back, but gas production does not appear to suffer. In other cases, gas rate is significantly lower than expected, but significant fracture fluid is recovered. With the inherent coupling of fracture length and permeability in welltest interpretation, and the practical impossibility of achieving radial flow in tight-gas reservoirs with large fracture lengths, it has been difficult to prove any theory about the cause of poor performance from tight-gas fracture treatments. This paper shows simulation results of these effects on post-fracture production from an unconventional (0.001 mD) gas well. Furthermore, realistic assumptions about proppant pack cleanup show a connection not only between poor cleanup and short effective fracture length, but also reduction in contacted kh and connected reservoir volume. New reservoir simulation results are presented showing 50% reduction of production in the first years due to these effects in unconventional reservoirs.

Tight gas fracturing was pioneered in North America in the 1970's and 1980's, and also has a relatively long history in Germany. In the rest of the world, however, massive fracturing for production from tight gas formations (i.e. k < 0.1 mD) has been very rare, due mainly to poor economics, rather than lack of opportunities. A massive oil field was recently discovered in Rajasthan (northwest India). The field development would require significant amounts of natural gas for heating and processing of the waxy oil to be produced. The most economical solution to provide sufficient gas in this remote desert location was to produce it from a deeper formation discovered in the same area. The majority of the gas is contained in a volcanic section of basalts and felsics. A fracturing campaign was performed in 2006 on three deep gas wells to evaluate the post-stimulation production increase from a number of different horizons, with base formation permeabilities varying from 0.005 to 0.15 mD. A comprehensive program of core testing, fluids compatibility testing and pre-fracture diagnostic injections was performed. Fracture stimulation treatments were performed in three different sections of this very thick gas-bearing formation (> 400 m gross height). The formations ranged from the highest permeability (0.15 mD) Fatehgarh sandstones, to a lower permeability Felsic section (0.05 mD) and the lowest permeability volcanic rock (0.005 mD). All three types of rock were stimulated successfully and post-fracture well testing showed initial production rates agreeing with what was expected based on reservoir simulation. This important result supports the proposition that unconventional gas resources in Asian countries can be attractive when stimulation techniques perfected in other areas (i.e. North America) are applied 1. Introduction The Raageshwari Deep gas field was discovered by RJ-E-1 (Raageshwari-1) in 2003. It was the second well drilled on the Central Basin High (CBH), a 40km-long composite feature of elevated N-S-oriented fault terraces, arranged in echelon within the Southern Barmer Basin of Rajasthan (Figure 1). The Central Basin High (CBH) structure is divided into many major horst blocks, of which Raageshwari is the shallowest. Raageshwari Deep is a tight lean gas condensate field and is contained in an arrowhead-shaped horst block formed at the confluence of three fault trends and contains 4 reservoir bodies (Fatehgarh, Basalt, Felsic and Sub-Felsic).

This p-W selected W presoniari by "in SPE Pmgmm C0mmitt6s followi~review of mafion contained m m sbabad sufnnitfd by ti author(s). Cmtenls d the psper, as sen~, have not been reviewed by tie S-of Petrolwm Engineers and am subject tõ i by the a~(s). W materisl, as~santed, does not -ssarily refld my positim of the Scciety of Pe~Eng-, its offii, w members, Papers pmeented at SPE mee~s m m-o~di mvi* by~T~Or@l Committees of the Smiety of Petroleum. Ewrneme Etimic re@tii, dmtritutii, w storage M any p&l of this~per fw mmmemfsl p~ses wifhwt h written Msent & h Society of Petrohum Engrn.sem is prtibifed Permissti f9 mpmdm in prht is restied to an sbstract of not more than 3C0 words; iilustra-msy ncd k wpied. Ths abstmct mm mntain~spiuus -wledgment of where and by Mom ths pnper wns pmsentd. Wie Libfmian, SPE, PO. Box S33836, Ritidson, TX 73Df33--, U.S.A, fax 01-972-9S2-9435. SummaryMinifrac tests are performed to estimate the key design parameters prior to propped-fiactire treatments: leak-off coeffl-cien~closure stress and net fracture overpressure. It is very important, especially in the case of Tip-Screen-Out or Fracand-Pack designs, to determine these parameters as accurately as possibIe, since errors will enhance the chances of a premature screen-out of'the propped 'fracture treatment.me key parameters are determined by analyzing the pressure decline 'afier a pump-iii-sfit-in test. For this analysis, one assumes that the pressure falls smoothly after shut-in. However, in many cases a momentary increase is observed in the welIhead pressure afier shutting in the pumps, which could compromise reliable interpretation of the pressure decline. Iñ rder to determine the cause of the pressure bump, we examined a soup of mini-fiat data sets which exhibited this momalous behaviour and mini-fiaci in comparable wells that showed a normal decline.We found that the cause of the pressure bump was severe .mderdispIacement of crosslinked gel at the end of pumping fie mini-fiat. The crosslinked gel at the bottom of the well-)ore may create a plug, which effectively makes the wellbore i closed vessel disconnected horn the fracture. Heating of the relatively incompressible fluid in the isolated wellbore section then causes the pressure to increase until the yield streng~~of the crosslinked gel has been overcome and tie plug starts to move downwards.This explains the observed bump in the pressure decline plot.To avoid this bump it is recommended to displace the crosslinked gel to the perforations or even slightly overdisplace. In our experience, if a pressure bump is still observed, it is best to check the calculated and measured displacement volume and repeat the minifrac. If this is impossible, the simplest correction for the pressure bump is to use the initial pressure decline before the bump, and shifi the final decline after the bump downwards by the magnitude of the bump. However, this procedure would be invalid if the point of fracture closure coincides with the bump. IntroductionMini-fiats provide key reservoir parameters for desi...