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.
The famous Arps empirical decline curves provide a powerful and practical tool for production forecast. Numerous historical production data proved that Arps decline curves can be applied universally. With that many engineers use Arps decline curve without knowing reservoir properties and operating conditions. The lack in reservoir properties and operating conditions affects the quality of production forecast. Even with the knowledge of reservoir properties and operating conditions a reliable production forecast still cannot be guaranteed if we do not understand the theory that connects reservoir properties and operating conditions to production decline. The demand for a solid theoretical basis for production decline curve analysis trigged this study.
In this investigation, we derived the governing equations of production decline for different reservoirs by combining static geological and reservoir data with dynamic production data. With these equations the Arps decline curves are reproduced for different reservoir fluids and drive mechanisms. These equations indicate that Arps decline curves not only are empirical but also have theoretical bases. Engineers can use our governing equations to forecast production confidently.
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.
In this study, a transient multiphase simulator has been used to characterize the fluid-hammer effects of well shut-in and start-up on the coupled subsurface and surface systems. The original work was performed by applying sensitivity analysis on a typical production system that includes well completion, wellbore, downhole equipment like packer etc., and the associated surface equipment like flowline, riser and valves. The data used in the study was taken from the published literature to summarize the general course of key factors that worsen the fluid-hammer effects. Fluid-hammer is also known as water hammer, a shock wave produced by the sudden stoppage or reduction in fluid flow.
Field operations such as pressure transient analysis, facility maintenance and workover require well shut-in process. For a typical production system, the resulted sudden rises in pressure can be critical because it has direct impact on equipment including unsetting of packer and may also cause possible damages to instrumentations. This paper provides estimates of the typical ratio of transient shock in pressure and flowrate over pre-condition values, and the duration of such pressure shocks. It also proposes the best location of the shut-in valve and the length of flowline to reduce the fluid-hammer effects.
This is a pioneering approach to integrated multiphase flow modeling of transient fluid-hammer effects, targeting flow assurance issues. This approach also can be applied to surface facility design and served as a guidance in field operation to avoid hydrocarbon leaks.
Multiphase flow in pipe has been intensively investigated since the oneset of oil and gas transportation by pipelines. As flow assurance problems keep arising in recent years, pipeline design solutions are desired for multi-phase flow system. The algorithms have widely guided the design of stream transportation from offshore well head to onshore terminal or platform. Operators would always seek cutting platform number or shut-in producing marginal field whose reserves cannot justify the construction cost. An accurate design of multiphase flow pipeline system is by all means demanded.
Traditional studies focus on gas-oil two-phase flow by deriving empirical or semi-empirical correlations that fit the experimental data. This study investigates a gas-oil-water three-phase pipe flow system. Starting from the momentum and mass conservation equations, force balance, and interaction relationships between different phases, we developed analytical solutions to estimate the pressure drop for stratified flow regime. This general approach can be applied to any gas-oil-water flowing systems. It provides a solid base for nodal analysis, pressure drop calculation for multiphase flow, artificial lift evaluation, etc. to help design and optimize production system. This work can be particularly useful for steady-state distance transportation.
In the boom of unconventional resource exploration, horizontal completion has been widely used. Horizontal well has the advantages of increasing productivity index, preventing gas or water coning, avoiding sanding out, enhancing drainage area, reducing drilling pad and footprint, and accelerating recovery. Although these advantages have been well recognized over vertical completion, the quantitative contribution is not yet to be investigated. The current design of horizontal well is primarily derived from field experience. This consists of more or less arbitrary contents. To fill this gap, this paper presents a model to incorporate production from different lengths of horizontal well, cost of the drilling and completion, discount of revenue, and cost by different timing. The achieved optimum horizontal well design leads to a maximized net present value (NPV) for operators.
Chokes are used to limit production rates to meet sale contract, comply with regulations, protect surface equipment from wearing out, avoid sand problems due to high drawdown, and control flow rate limited by capacity of the facility. Single gas phase flow through choke is vital to oil industry because not only an accurate estimation of gas flow rate guarantees a reliable supply to the end users, thus the predictable revenue from gas sale for the company, but also protect the equipment from breaking as a result of high gas rate. Nevertheless, importance of gas metering cannot be overemphasized. Gas flow through choke had been studied by numerous investigators, Different choke flow models are available from the literature, and they have to be chosen based on the flow regimes, that is, subsonic or sonic flow. The most common used flow equations developed by Shapiro, Zucrow and Hofmann are used for subsonic and sonic flow, respectively. Sonic flow happens when downstream to upstream pressure ratio is equal to critical pressure ratio.
A careful review of these equations indicated that they are not theoretically rigorous and give inaccurate gas flow rate for the real gas. Thus these equations need to be modified in order to be used to calculate gas flow rate under both flow regimes. After a thoroughly analysis and derivation we came up with equations that have solid base. New correlations that reconcile the issue caused by approximation method used to derive the old gas flow equations were based on both engineering judgment and physical phenomenon. The error in the old equation can be corrected with the new equations. New equations provide good approaches to quantify gas flow through choke.
Gas transient flow in pipeline and gas tank is critical in flow assurance. Not only leak detection requires a delicate model to simulate the complicated yet drastically changed phenomena, but also pipeline and tank design in the metering, gathering, and transportation system demands an accurate analysis of gas transient flow, through which efficient, cost-effective operation can be achieved.
Traditionally there are two types of approaches to investigate gas transient flow: one is treating gas as ideal gas so that ideal gas law can be applied; another is considering gas as real gas thus gas compressibility factor comes into play. Needless to say, the former method can result in an analytical solution to gas transient flow yet with a deviation from the real gas performance, which is very crucial in daily operation. The latter approach needs numerical method to solve the governing equation, thus leads to unstable issue but with more accurate result. Our literature review indicated that no study considered the effect of changing gas viscosity on the transient flow is available. Therefore, this effect was included in our study.
Our investigation showed that viscosity does have significant influence on gas transient flow in pipe and tank leakage evaluation. In this study, a comprehensive evaluation of all variables was done to find out the most important factors in the gas transient flow. Several case studies were used to illustrate the significant of this study. Engineers can do a more reliable evaluation on gas transient flow by following the method we used in our study.
The famous Buckley-Leverett displacement mechanism has been used to predict the performance of waterflood. With Buckley-Leverett method, oil recovery from waterflood is calculated and required water injection volume to achieve that oil recovery is estimated. This method does provide a very useful tool in waterflood design. Our experience in oil industry and a thorough literature review indicates that petroleum engineers used Buckley-Leverett method to analysis waterflood project directly without any adjustment basing on the real reservoir and production situations. By doing so, a lot of errors are introduced into the analysis.
It should be noted that Buckley-Leverett method assumed displacement occurs in a linear system. This is true for some waterflood scenarios while for others it is not. For some waterflood scenarios a radial system is more appropriate than a linear system. In this study we investigated the fractional flow in a radial system and derived the solutions to predict the performance of water displacing oil in radial system. With this radial displacement model, design and prediction of waterflood can be achieved by Buckley-Leverett method or our model, whichever fits the waterflood pattern. Considering the fact that many waterflood scenarios follow radial displacement, our model is an important supplement to Buckley-Leverett method.
For oil reservoir with bottom water and/or gas cap, gas and water conings impose serious problems during the oil production. Coning leads to the premature gas and water breakthrough thus results in high water cut and gas oil ratio, which require a higher surface facility capacity to process excessively produced water and larger three-phase separators to separate gas, oil, and water. Consequences of early breakthrough are large footprint due to large facility, more energy to operate field, and low oil recovery. Even though numerous studies had been focused on solving the critical oil rate for gas and water coning problems, to our knowledge none of them considers the effect of capillary pressure on critical oil rate. The ignorance of capillary pressure caused the error of calculated critical rate to rise to 300%, according to the real field case study.
The errors caused by neglecting capillary pressure are severe in low permeability reservoirs. For the purpose of good production design, we investigated the effect of capillary pressure on critical rate estimation. Our study showed that the calculated critical rates are close to real field critical rates. The existing methods underestimate the critical rate by not taking capillary pressure into account. Therefore, more accurate critical rates can be obtained using our method. With more accurate result more reliable production plan can be designed to maximize the ultimate recovery.