Gas transient flow in a gas pipeline and gas tank is critical in flow assurance. Not only does leak detection require a delicate model to simulate the complicated yet dramatically changed phenomena, but gas pipeline and gas tank design in metering, gathering, and transportation systems demands an accurate analysis of gas-transient flow, through which efficient, cost-effective operation can be achieved.
Traditionally, there are two types of approaches used to investigate gas-transient flow: one involves treating gas as ideal gas so that the ideal gas law can be applied and the other considers gas as real gas, allowing the gas compressibility factor to come into play. Needless to say, the former method can result in an analytical solution to gas transient flow with a deviation from the real-gas performance, which is very crucial in daily operation. The latter approach requires a numerical method to solve the governing equation, leading to instability issues with a more-accurate result. Our literature review indicated that no study considering the effect of changing gas viscosity on the transient flow was available; therefore, this effect was included in our study.
Our investigation showed that viscosity does have a significant influence on gas-transient flow in pipe- and tank-leakage evaluation. In this study, a comprehensive evaluation of all variables was performed to determine the most-important factors in the gas-transient flow. Several case studies were used to illustrate the significance of this study. Engineers can perform a more-reliable evaluation of gas transient flow by following the method we used in our study.
Natural gas exploration and production from shale gas formations have gained great momentum throughout the world in the last decade. Producing natural gas from shale is challenging because of the high uncertainty in well productivity. It is
imperative to investigate and understand the gas flow mechanism in the shale gas formations. This paper investigates the shale gas production mechanism based on field case studies.
Guo et al.'s analytical well productivity model was employed in this work for analyzing gas productivity of a shale gas well in the Fayetteville Shale basin. Model analyses indicate that shale heterogeneity (natural fractures/custers and organics spots)
is a favorable characteristics of shale gas reservoirs because they contribute to the initial and long-term well productivity. Shale gas reservoirs without natural fractures/clusters will not produce natural gas at commercial rates even a few hydraulic
fractures are created. The intensity of natural fractures/clusters is a key factor affecting the potential of shale gas wells. Hydraulic fractures are useful for intersecting natural fractures/clusters to make well more productive, but it is not necessary
to create high-conductivity fractures for this purpose. Shale gas wells should be placed in the areas where high-natural fracture intensity and solid organic material contents are present.
Producing natural gas from shale-gas reservoirs presents a great challenge to petroleum engineers owing to the low-permeability nature of this type of gas reservoir. Large-scale and expensive hydraulic-fracturing operations are often required for enhancing gas well productivity. Because of the shaly characteristics of the reservoir rock, the hydraulically fractured gas wells are vulnerable to damage by fracturing fluids. However, the true significance of the formation damage in shale-gas reservoirs is still not clear. It is highly desirable to have a simple method for predicting the degree of fracture-face matrix damage and for optimizing fracturing treatments. This paper is meant to fill this gap.
A new mathematical model was developed in this study to predict the effect of fracture-face matrix damage on the productivity of fractured gas wells in shale-gas reservoirs. A unique feature of the new model is that it considers reservoir/fracture crossflow in finite-conductivity fractures. Results of the model analyses were sensitized to reservoir properties and facture-face matrix-skin properties determined by the fracturing-fluid properties and treatment conditions. Large ranges of possible leakoff and spurt-loss coefficients were investigated. We concluded that, in the ranges of reservoir and fluid properties used in this study, well productivity should drop by less than 15% even if the residual matrix permeability is reduced to only 5% of the virgin reservoir permeability in the damage zone. Neglecting the resistance to flow in the fracture will overestimate the effect of matrix damage on well productivity. The well-productivity drop caused by matrix damage is most sensitive to the invasion depth and damaged permeability.
Young Technology Showcase - No abstract available.
Optimizing the completion interval to minimize water coning has been long recognized as a challenge in the industry. After reviewing the mechanism of water coning, a simple analytical model is presented in this study for water-coning systems in high-conductivity reservoirs (reservoirs with low pressure gradient). This model is applicable to predict the critical rate and to determine the optimum wellbore penetration for achieving maximum water-free production rate of vertical oil wells.
The developed model predicts the critical rate on the basis of a radial/spherical/combined (RSC) 3D flow field assumption that takes into account the effect of permeability anisotropy, density difference between water and oil, and limited wellbore penetration. Moreover, optimum wellbore penetration into the oil zone has been determined by maximizing the critical rate. This analytical model reveals the optimum wellbore penetration in high-conductivity reservoirs to be almost half of the pay-zone thickness, depending on the radius of wellbore and drainage area, pay-zone thickness, and the permeability anisotropy of the reservoir.
Large scale hydraulic fracturing operations are often required for enhancing productivity of wells in shale gas formations. Due to the shally characteristics of the formation rock, the productivity of the hydraulically fractured gas wells seems to be very vulnerable to the damage by the fracturing fluids. The damaging mechanisms are believed to include fluid invasion, proppant embedment, gel filter cake at the fracture face, and the gel residue in the proppant pack. The relative significance of the formation damage due to each of the mechanisms is not clear. This paper presents result of investigations based on a new analytical model.
A new analytical well productivity model was developed in this study, considering the matrix cross-flow to long fractures and non-linear influx to short fractures. A new model involves parameters that describe the effects of fracture fluid filtration, proppant embedment, gel filter cake at the fracture face, and the gel residue in the proppant pack on the productivity of fractured gas wells in shale gas formations. Sensitivity analyses with the model show that, fracturing fluid invasion, proppant-embedment layer, gel filter cake residue at the fracture face, and gel residue inside the fracture may reduce well productivity by upto 12.5%, 0.6%, 6%, and 7%, respectively. The significance of the damage to well productivity should not affect gas production rate in a way that would be noticed.
Cold heavy-oil production with sand (CHOPS) has been widely used for recovering heavy oil from unconsolidated sandstones (UCSs). Although this technology is considered to be mature in some oil fields in Canada, there are some technical issues that need to be addressed when this technology is transferred to fields in other parts of the world. These issues are primarily related to the variations in local geological and reservoir conditions. One of the concerns is whether the designed well production rate is high enough to self-clean the wellbore against sand accumulation. During planning of CHOPS completions, it is imperative to know if the designed fluid-production rate will be adequate to carry sand to surface, especially when horizontal wells are employed, where a significant amount of sand can accumulate in the horizontal wellbore that can kill the well. However, it is not clear what constitutes the "adequate" fluid-production rate. A theoretical investigation of sand transport in heavy oil was conducted in this study. A critical fluid-production rate was defined to quantitatively describe the "adequate" production rate required to carry sand to surface in vertical, inclined, and horizontal wells. Also developed in this study is a CHOPS-well deliverability model based on self-stimulation of reservoir and oil/water/gas/solid four-phase flow in the production string. Combined use of the critical-production-rate model and the well-deliverability model allows for optimal selection of pumps that will ensure the smooth production of fluids in CHOPS operations. This paper provides petroleum engineers with essential knowledge and information for planning CHOPS well completions.
Inflow-control devices (ICDs) were developed in response to early water breakthrough from the heel of prolific horizontal wells. In their initial applications, the design of ICD installations was based on equalizing flux (flow rate per unit length) along the length of a horizontal well, which required "choking" of flux in the heel region. In practice, these tools are often installed along the entire length of a horizontal well, with the logic that, because choking level is proportional to flow, the tool will automatically produce a more uniform flow profile.
In this paper, we will re-examine the technical validity of equalizing flux along the length of the horizontal well. We will show that, in reservoirs with uniform permeability, the flux from the toe and heel regions should, in fact, be larger than that from the midsection. We will also show that delaying water or gas breakthrough is not the best reason for using ICDs. We will discuss the benefits of a new design philosophy whereby the well is segmented and choked at a level that regulates its flux to a value that produces a more-suitable flow for optimum reservoir management. This gives the operator the flexibility to design ICD layout to optimize various flow parameters, including time or cumulative production at water/gas breakthrough, location of first water/gas breakthrough, or any other parameter that fits the production strategy. This will be especially valuable for wells in variable-permeability reservoirs. A new design philosophy developed on the basis of this concept will be presented and its benefits demonstrated through a case history.