Top PDF The Flow Regimes Associated with Hydraulic Fractured Horizontal Wells in Shale Formations

The Flow Regimes Associated with Hydraulic Fractured Horizontal Wells in Shale Formations

The Flow Regimes Associated with Hydraulic Fractured Horizontal Wells in Shale Formations

10 model with No hydraulic fractures, 1, 2, 4 hydraulic fracture stages. The hydraulic fracture stages were placed as summarized in table 4 to have uniform spacing. The grid-size in the model was chosen as 10 feet in all directions. The early production rates were found to be significantly higher than the rest of the production profile. This problem is due to the fact that the model treats the first grid block next to the wellbore as the hydraulic fracture. Consequently, the fracture dimensions, in a model with large grid blocks, are significantly larger than the actual fracture dimensions. This leads to over-prediction of the production rate at early times. To resolve this issue, the simulation runs were performed using minimum grid sizes of 1 ft. in all directions. It should also mention that the run-time for the model with small gird blocks was excessive. After comparing the new results to previous results, it became clear that after 3 to 4 years of production, the simulated production rates were almost identical for both runs. In order to have consistent results while reducing the run-time, the first 5 years of the production was simulated using the model with smaller minimum grid size and the remainder of production profile was obtained from the model with the larger minimum grid block size.
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Pressure derivative analysis for horizontal wells in shale reservoirs 
		under trilinear flow conditions

Pressure derivative analysis for horizontal wells in shale reservoirs under trilinear flow conditions

Case 2 involves the acting of five flow regimes (Figure-2): Bilinear, first linear and first pseudosteady- state period of case 1; then, second linear and second pseudosteady-state. Followed by the first pseudosteady- state period, and after a considerable response time, the pressure changes linearly with time and the second linear flow can be observed; once the transient wave reaches the hydraulic fracture limits or the internal reservoir boundary, the second pseudosteady-state period is developed. There exists a certain relationship between  -  and the second linear flow regime. Frequently, when  has large values, the second linear flow becomes visible in the pressure derivative versus dimensionless time log-log plot; when  grows, the duration of the second linear flow also does so, and this, in turn, occurs late, as  becomes small.
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Carbon dioxide injection and associated hydraulic fracturing of reservoir formations

Carbon dioxide injection and associated hydraulic fracturing of reservoir formations

4 The advent of developments in numerical techniques have prompted more studies (Al-Busaidi et al., 2005, Alqahtani and Miskimins, 2010, Boone and Ingraffea, 1990, Boutt et al., 2007, Boutt et al., 2011, Casas et al., 2006, Dean and Schmidt, 2009, El Shamy and Zeghal, 2005, Hoffman and Chang, 2009, Jansen et al., 2008, Lam and Cleary, 1986, Lujun et al., 2009, Papanastasiou, 1997, Rungamornrat et al., 2005, Shimizu et al., 2009, Shimizu et al., 2011, Warpinski et al., 1982, Yamamoto et al., 1999, Yew and Liu, 1993); these have added flexibility that complement field/laboratory experiments which, on their own, have limited and controlled conditions. Examples of the application of numerical methods include the finite element modelling technique used by Alqahtani and Miskimins (2010) to determine the stress distribution caused by the application of predefined sets of triaxial stresses on layered block systems (in order to simulate laboratory experiments) and the use of finite difference techniques by Hoffman and Chang (2009) to model hydraulically fractured wells and predict productivity. In addition, Dean and Schmidt (2009) illustrated the capability of a multiphase/multi-component modelling technique that couples hydraulic fracturing with other processes such as flow through porous media, heat convection and conduction, solids deposition and poroelastic/ poroplastic deformation.
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Regulation of Water Pollution from Hydraulic Fracturing in
Horizontally-Drilled Wells in the Marcellus Shale Region, USA

Regulation of Water Pollution from Hydraulic Fracturing in Horizontally-Drilled Wells in the Marcellus Shale Region, USA

lie deep underground. With the introduction of horizontal drilling, new commercial sources of energy have become available. Wells are drilled and injected with large quantities of water mixed with specially selected chemicals at high pressures that allow petroleum reserves to flow to the surface. While the increased economic activities and the outputs of domestic energy are welcomed, there is growing concern over negative environmental impacts from horizontal drilling in shale formations. The potential for water contamination, land destruction, air pollution, and geologic disruption has raised concerns about the merits of production activities used during extraction. This paper looks at the impacts of horizontal drilling using hydraulic fracturing on water supplies and takes a comprehensive look at legislative and regulatory approaches to mitigate environmental risks in the Marcellus shale region. The overview identifies shortcomings associated with regulatory controls by local and state governments and offers two policy suggestions to better protect waters of the region.
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Analysis of the Gas Production from Marcellus Shale Horizontal Wells Using Decline Curves

Analysis of the Gas Production from Marcellus Shale Horizontal Wells Using Decline Curves

The increased interest and demand of the unconventional gas reservoirs to supply the United States with hydrocarbons created new challenges for resource exploration and development. Because of the ultra-low permeability and the nature of the shale formations, it is necessary to hydraulically fracture almost every well to achieve economical production. The technology of multi-stage hydraulic fracturing and horizontal drilling has provided access to the gas stored in these formations allowing a commercial amount of the gas to be produced. This increased interest in shale gas production requires a better understanding of the production behavior and a reliable technique that can help in predicting a long-term production performance. Many challenges present themselves when production is being forecasted in ultra-low permeability unconventional reservoir systems. One of the major challenges is the lack of understanding of the interaction among the fluid flow, the hydraulic fracturing, and the reservoir characteristics in these complex systems. Therefore, the production performance of the shale gas wells over the longer time periods have not been established.
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Will Unconventional, Horizontal, Hydraulic Fracturing for Shale Gas Production Purposes Create Environmental Harm in the United

Kingdom?

Will Unconventional, Horizontal, Hydraulic Fracturing for Shale Gas Production Purposes Create Environmental Harm in the United Kingdom?

Therefore, the constituents of produced water can vary over time because of the variety of materials and substances used in UHF operations, and the complex geological make-up of underground formations. This produced water must be disposed of safely in the UK because it is considered as mining waste by the EA under the European Union (EU) Mining Waste Directive 2006/21/EC (Bryden et al. 2014: 30). Fracfluid mining waste is also affected by the Water Framework Directive (requiring an environmental permit as well as pre-treatment, before discharge into a well), and the Radioactive Substances Regulation (for wastewater containing Naturally Occurring Radioactive Material (NORM) requires another environmental permit) (RSRAE, 2012: 21). Produced water can either be disposed of by treatment at a water treatment facility (BGS, 2012: 15), by re-injecting the fluid back into the well (RSRAE, 2012: 14) or by discharge to nearby surface waters (BGS, 2012: 15). Treatment requires keeping flow-back water in retention pits which can ‘be used to store additional make-up water for drilling fluids or to store water used in the hydraulic fracturing of wells’ (BGS, 2012: 15). Retention pits are temporary solutions to dealing with the produced water that returns to the wellbore in the first few days and weeks of hydraulic fracturing.
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The workflow to analyze hydraulic fracture effect on hydraulic fractured horizontal well production in composite formation system

The workflow to analyze hydraulic fracture effect on hydraulic fractured horizontal well production in composite formation system

i.e., f 1 = u and f 2 = ηu. The flow regimes are as follows: (1) the early bilinear flow period characterized by a slope of 1/4 in the pressure derivative curve; (2) the early linear flow characterized by a slope of 1/2 in the pressure derivative curve. During the first linear flow, each fracture produces indepen- dently with the oil flowing perpendicular to the fracture; (3) the early radial period around individual fractures marked by a constant pressure derivative which is 1/(4*N) on the type curve. This regime can occur if the fracture spacing is large enough compared to the fracture half-length; (4) the second linear flow period by a slope of 1/2 in the pressure derivative curve; (5) the second radial flow by a horizontal straight line in the derivative curve which is 1/2; (6) the transition flow period between second radial flow and the third radial flow; (7) the third radial flow characterized by a 1/2*M horizontal straight line in the derivative curve. Compared with the type curves for horizontal wells in the homogenous single porosity reservoir (shown in Fig. 3, there are three more flow regimes for the MsFHW in composite system, as shown as regimes (6) and (7) in Fig. 4a. Fig. 4b shows the 3D maps for the seven flow regimes discussed above. As can be seen, as time increases, pressure will spread from near the hydraulic fracture to away from it. In regime four, hydraulic fractures begin to interfere with each other. In regime six, pressure spreads to the outer region and the pressure and rate transient curves reflects the outer region formation parameters.
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Pressure and pressure derivative 
		interpretation for vertical wells in naturally fractured and 
		compressible formations

Pressure and pressure derivative interpretation for vertical wells in naturally fractured and compressible formations

the TDS Technique is that in certain cases flow regimes can be artifitially created without risking the interpretation. Then, from the permeability, the pressure derivative value for nonstress sensitive case is determined. This is represented by a horizontal line on the pressure derivative versus time log-log plot. Then, this value is used for the estimation of the mechanical skin factor; therefore, the geometrical skin factor is readily estimated by substrating the mechanical skin factor from the toal skin factor. Well developed correlations are provided for correcting the minimum point affected by the stress and the intercept between the unit slope and horizonatl radial flow regime lines. With that, the equations already presented by Engler and Tiab can be readily estimated. The expressions were successfully applied to simulated examples.
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Improving Fluid Recovery and Permeability to Gas in Shale Formations

Improving Fluid Recovery and Permeability to Gas in Shale Formations

The coreflood setup consisted of a core holder, four accumulators, a syringe pump, and a hydraulic pump, as shown in Fig. 7. The core samples were placed in the core holder with a heating jacket around it to simulate reservoir temperature. An ISCO syringe pump was used to inject the fluids that were stored in stainless-steel accumulators at room temperature, into the core at a constant rate. The overburden pressure on the core was applied using a hydraulic pump by injection of hydraulic oil in an oil tank between the internal surface of the core holder and the rubber sleeve that cased the core. The flow was controlled by using two backpressure regulators to avoid any undesirable high pressure after heating the system. One of these was used to regulate the core outlet flow at a pressure of 700 psi and the other to keep the overburden pressure at 1800 psi. A differential pressure transducer was used to measure the pressure drop between the core inlet and outlet. The effluent samples were collected in a compact fraction collector.
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Formation damage in horizontal and deviated wells

Formation damage in horizontal and deviated wells

Since the advent of the energy crisis and the Arab embargo, most of the oil companies started to realize and aware of the importance of maximizing well productivity through the prevention of formation damage. Formation damage, sometimes known as wellbore damage, is a process that impairs the permeability of a reservoir and consequently decreases the natural flow of fluids from the reservoir into formation. It can occur in many ways and one of them is during the drilling phase. Laboratory studies [1 – 4] indicated that operations in a field such as drilling, completion, workover, production, and stimulation are the potential sources of formation damage.
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REVIEW ON HOLE CLEANING FOR HORIZONTAL WELLS

REVIEW ON HOLE CLEANING FOR HORIZONTAL WELLS

[12] addressed a new drill pipe design integrating hydro-mechanical features in each tool joint has been developed to overcome limitations of mechanical hole cleaning devices (MCDs) in smaller diameter holes, and to extend the applications of hydro -clean drill pipe to ERD (Extended Reach Drilling) well. [13] presented a detailed combination of Larsen's model and Moore's correlation to predict and calculate the minimum flow rate for cuttings removal for all range of inclinations namely from 0° to 90°. [14] conducted several cuttings transport experiments, using a large-scale flow-loop apparatus and field measurement of annular pressure, using PWD (pressure while drilling) in a geothermal directional well recently drilled in Japan. Numerical simulation for the targeted long extended-reach geothermal well with a total depth 3,000 m, horizontal departure of 2,500 m, and maximum hole inclination angle of 70° was performed using a transient hydraulics simulator. [15] examined critical factors that affect the efficient cleaning/transport of cuttings and bit hydraulics in inclined wells with a view to understanding how to minimize drilling difficulties thereby reducing non-producing time (NPT) during drilling operations. [16] developed a new method to optimize multiple hole cleaning parameters by introducing the ant colony algorithm. The flow rate, consistency coefficient in power law model and nozzle flow area, which are three easily-adjusted parameters to control the hole cleaning on drilling site, are selected as the optimization variables. [17] explained the effect of the cuttings bed properties on hole cleaning in detail and demonstrated how the drilling operations were improved compared to earlier drilling operations using conventional drilling fluids. From drilling operations in North Sea fields, it is shown how the total drilling progress is improved. [18)] developed a transient cuttings-transport model by integrating closure laws for cuttings transport into a transient drilling model.
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Performance Model for Vertical Wells with Multi-stage Horizontal Hydraulic Fractures in Water Flooded Multilayer Reservoirs

Performance Model for Vertical Wells with Multi-stage Horizontal Hydraulic Fractures in Water Flooded Multilayer Reservoirs

zone, and moving up the wellbore to repeat this process at next desired productive interval [4]. Many authors have studied the performance of vertical wells with vertical fractures [5-7]. However, the performance model of vertical wells with horizontal fractures has been investigated occasionally, and most studies focus on numerical solutions. W. Sung (1987) compared the performance of producers with vertical and horizontal fractures by numerical reservoir simulation [8], and Peter Valko (1998) studied the transient behavior of finite conductivity horizontal fractures [9]; Lasen Leif (2011) studied the pressure in multilayer reservoirs influenced by horizontal fractures [10]. However, few studies have been devoted to an analytical solution for the productivity of vertical wells with horizontal fractures considering oil-water two-phase flow in regular waterflooding patterns. In this paper, an accurate productivity model for vertical wells with horizontal fractures is proposed in conjunction with threshold pressure, material balance, and pressure superposition, for the sake of making better engineering decisions about the development of the reservoirs with complex hydraulic fracturing.
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A two phase flowback model for multiscale diffusion and flow in fractured shale gas reservoirs

A two phase flowback model for multiscale diffusion and flow in fractured shale gas reservoirs

5.2.4. Effect of Fracture Geometry. In the simulation model, the hydraulic fracture is usually assumed to be a straight line. This may deviate from the real case where the complicated fracture network is formed. The assumption of straight line may affect the distributions of gas and water pressure, further changing the gas production rate. In order to reveal the effect of fracture geometry on gas and water production, the gas drainage maps are presented in Figure 10. After the 36.5 days, the fractures in both geometry 1 and geometry 2 have their own drainage area. The hydraulic fractures would have an interference with neighboring fracture network to form an integrated drainage area. The drainage area varies with the geometric shape of fractures. If the height of fracture is the same, the length of fracture in geometry 2 is longer because of tortuosity. This means that the hydraulic fracture has a larger contact area with the surrounding fractured zone. Figure 11 compares the gas production rates in geometries 1 and 2. Because geometry 2 adds the contact area, its gas production rate is always higher. This effect is similar to that of fracture uniformity.
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Optimizing oil production in horizontal wells (water/oil cresting in horizontal wells)

Optimizing oil production in horizontal wells (water/oil cresting in horizontal wells)

Naturally, the reservoir exists at static condition with the gas, oil and water separated by gravity, in order of their density differences (Balazs et al., 2009, Beveridge et al., 1970, Singhal, 1996). Due to the lower viscous nature of water and gas compared to oil, no restriction to flow is imposed by the reservoir rocks and thus a phenomenon called coning/cresting could occur. Coning in vertical wells (conical in shape) and cresting (crest- like shape) in horizontal wells is defined as the phenomenon in which an underlying bottom water moves upward or overlying gas cap moves downward against gravity into the completion interval through the perforations of a producing oil well. This is a problem associated with oil production in reservoirs underlain by strong aquifers (in terms of water coning/cresting), a common scenario in major hydrocarbon provinces of the world. However, some reservoirs have weak aquifers thus, produce little or no water during oil production. In the former scenario, the reservoir is subjected to rapid water or gas migration towards the completion zone, a resultant effect of high-pressure drop around the wellbore area. The WOC and GOC are first defined at static condition as illustrated in Figure 2-18 (top left) before the commencement of oil production.
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Article Physical scaling predicts oil production rates and ultimate recovery from all horizontal wells in the Bakken shale

Article Physical scaling predicts oil production rates and ultimate recovery from all horizontal wells in the Bakken shale

Figure 15. The stacked bars show the numbers of existing wells from the DrillingInfo dataset in 2019, and the potential wells from the EIA report [6] in each Bakken TPS assessment unit mapped onto the corresponding counties in the Middle Bakken and Upper Three Forks Formations. The lines show the corresponding EUR values from the physical scaling and the EIA statistical predictions. The P 10 , P 50 ,

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The Performance of Fractured Horizontal Well in Tight Gas Reservoir

The Performance of Fractured Horizontal Well in Tight Gas Reservoir

performance depends on numerous parameters including reservoir properties and fracture geometries which both contain uncertainty and it is not surprised that a perfect match was not obtained. From the results (Fig. 43), the higher production rate at early time from the slab model could be caused by the assumptions of ideal condition of fractures and neglected Non-Darcy effect inside fracture. The proppant permeability used in the history match is the effective permeability. The effective permeability contains two parts, one is the proppant permeability and the other is the natural fracture permeability. In this case, the connection between natural fractures and hydraulic fractures are unknown factor, the source function cannot directly applied in the natural fracture system. The natural fracture permeability has been represented here as an effective proppant permeability in the hydraulic fractures.
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CO2 injection-induced fracturing in naturally fractured shale rocks

CO2 injection-induced fracturing in naturally fractured shale rocks

Under tri-axial loading of x:y:z= 1100:1600:2100 psi (Figure 12), shale sample 5 was fractured by injecting a synthetic slick-water which consisted of 0.1 wt% hydrolyzed polyacrylamide, 2.0 wt% KCl, and red dye. At 20 °C, the viscosity of this synthetic slick-water, measured with a rotating cylinder viscometer, is 1.8 mPa·s. Figure 13 shows the borehole pressure profile during the slick-water injection. Injection started at 1 ml/min, and pressure reached the first peak of 521.3 psig at 1281.1 seconds. Ten seconds later, the pump was stopped to allow pressure drawdown. Seeing that borehole pressure leveled out near 100 psig, we restarted the pump at 1 ml/min, and the pressure reached the highest peak of 1602.5 psig at 2352.6 seconds. After 10 seconds, the pump was again stopped. Unexpectedly, file corrupted around 2500 seconds and the data acquisition system was restarted. This caused the data gaps in both Figure 12 and Figure 13. As pressure leveled out near 180 psig, the pump was restarted at 1 ml/min, and a small peak of 309.7 psig was achieved at 3562.2 seconds, then pressure slowly decreased, suggesting the fracture propagation stage. Later, we increased the injection rate to 10 ml/min, and a pressure peak of 434.7 psig was reached at 4256.2 seconds. In tens of seconds, fluid leak off was observed on the sample faces and pump was turned off. On the tri-axial stress curves, there are slight responses on x-, y-, and z-stress corresponding to the last pressure peak, while all earlier pressure peaks including the highest one did not bring about any obvious responses. This suggests that probably only the last peak created new fractures or extended preexisting fractures, whereas all other peaks only broke through the weakly bonded preexisting fractures.
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Evaluation of Critical Fracture Skin Porosity For Contaminant Migration In Fractured Formations

Evaluation of Critical Fracture Skin Porosity For Contaminant Migration In Fractured Formations

(4) Transport along the fracture is much faster than transport within the fracture skin and the matrix. Local equilibrium is assumed for the mass partition mechanisms in the fractured system throughout the flow domain as an approximation at the macroscopic scale. Local equilibrium assumption can be used if the contaminant sorption onto or desorption from the fracture surface is sufficiently fast relative to the convective transport. In the fracture, velocity is assumed to be constant with time and uniform in space and the water flow is assumed to be laminar. Solute transport processes in the fracture-skin-matrix system can be described by coupled one- dimensional equations, coupling being provided by the continuity of fluxes and concentrations at the interface. The differential equation for the fracture is based on mass balance for an element in the fracture. Solute transport processes in a fracture-skin-matrix system can be described by coupled one-dimensional equations, the coupling being provided by the continuity of fluxes and concentrations at the interface. The governing differential equations for the fracture is given by
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Comparison of Emperical Decline Curve Analysis for Shale Wells

Comparison of Emperical Decline Curve Analysis for Shale Wells

The decline methods shown here have different models and equation forms, thus often provide different forecasts. Arp’s hyperbolic equation can be shaped into a straight line to fit either bilinear or linear flow with b values of 2 and 4 respectively. However, it cannot model multiple flow regimes. The PLE is the only method that models transient and BDF decline. The SEPD model is difficult to shape into a straight-line because of its equation formulation. Duong’s is the only method that models clean-up while the LGM is the easiest method to use. If BDF is expected, the EUR cannot be accurately established until BDF is observed. Four cases that represent the typical flow regimes of shale wells were simulated to evaluate which method(s) is/are best for each case:
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Economic analysis of shale gas wells in the United States

Economic analysis of shale gas wells in the United States

the volume of gas that can be economically produced. What this means for operators is that a small decrease in costs can have a large effect on whether or not individua[r]

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