Wellbore Pressure Loss Research Articles

Dynamic modelling and engineering simulation of fluid mechanics in water injectors

To study the fluid dynamic response mechanism under the working condition of water injection well borehole, based on the microelement analysis of fluid mechanics and the classical theory of hydrodynamics, a fluid microelement pressure-flow rate relationship model is built to derive and solve the dynamic distribution of fluid pressure and flow rate in the space of well borehole. Combined with the production data of a typical deviated well in China, numerical simulations and analyses are carried out to analyze the dynamic distribution of wellbore pressure at different injection pressures and injection volumes, the delayed and attenuated characteristics of fluid transmission in tube, and the dynamic distribution of wellbore pressure amplitude under the fluctuation of wellhead pressure. The pressure loss along the wellbore has nothing to do with the absolute pressure, and the design of the coding and decoding scheme for wave code communication doesn't need to consider the absolute pressure during injecting. When the injection pressure is constant, the higher the injection flow rate at the wellhead, the larger the pressure loss along the wellbore. The fluid wave signal delay amplitude mainly depends on the length of the wellbore. The smaller the tubing diameter, the larger the fluid wave signal attenuation amplitude. The higher the target wave code amplitude (differential pressure identification root mean square) generated at the same well depth, the greater the wellhead pressure wave amplitude required to overcome the wellbore pressure loss.

Effect of Fluid Viscosity and Fiber Length on the Performance of Fibrous Fluid in Horizontal Well Cleanout

SummaryDuring drilling, completion, and intervention operations, solids can deposit in the wellbore. Innovative cleanout fluids reduce the problems associated with inadequate hole cleaning. Various methods have been developed to improve hole cleaning, but their effectiveness decreases as the wellbore inclination increases. One way to solve this issue is to add fibers to the drilling fluid and reduce the settling velocity of the solids to improve the fluid’s lifting capacity.The purpose of this study is to evaluate the cleanout performance of fibrous fluids in horizontal wells using a large-scale flow loop. Thus, flow loop experiments were conducted to assess the impact of fiber on equilibrium bed height. The experiment measures equilibrium bed height and pressure loss in an eccentric annular test section. During the investigation, the flow rate and apparent viscosity of the fluid and fiber length were varied.The results demonstrate the effectiveness of long fiber (length = 0.5 in.) in improving hole cleanout in horizontal wellbores. When a small amount (0.04% wt.) of long fiber was added, the cleanout performance of the high-viscosity fluid did not show a noticeable change. In contrast, the performance of the low-viscosity fluid improved. Even though adding fiber has minimal impact on the apparent viscosity of the fluids, the long fiber improved the cleaning performance of the low-viscosity fluid.Hole cleaning is challenging in operations such as coiled tubing (CT) in which rotating the drillstring is impossible. Hence, this study focuses on cleanout operations in horizontal wellbores without drillstring rotation. The novelty of this work lies in demonstrating how the adjustment of fluid viscosity can positively impact the hole cleaning performance of fibrous fluids in the absence of pipe rotation. The study also presents a new approach to modeling the effects of solids bed irregularity on wellbore pressure loss and equivalent circulating density (ECD).

Performance and behavior of a horizontal well in reservoir subject to double-edged water drive

Determining the performance and behavior of horizontal well subjected by double-edge water drive reservoir at a late time period has been a concern to many researchers. Wellbore pressure losses during production in horizontal well increase conning propensity at late period thus rendering some part of the horizontal well unproductive. This restricts the effectiveness of increasing the horizontal well length due to wellbore pressure losses along the horizontal well. This study was carried out by using source function and Newman rule to develop models to predict the performance and behavior of a horizontal well which was subjected by double Edgewater and numerical method was used for the computation and Sensitivity analysis of parameters was performed. The results show that the performance and behavior of the reservoir for this study were found to be when the well is position at well length (XWD: YWD: ZWD), in the ratio of 12:7:15 respectively.
 Keywords: Double edged, Performance, Reservoir, Water Drive, Late Period.

Modeling the effect of entrained sand particles on pressure transverse in a flowing gas well

PurposeThe purpose of this study showcase a realistic model for estimating pressure drop at any production time in any location along the vertical flowing solid-gas well. Also to simulate the impact of solid particles on the pressure transient in gas well. The production of natural gas from the reservoir is always associated with entrained solid particle of different sizes, mainly sand particles and crystalline salts. Entrained solid transport along the gas phase has been a great concern for gas production engineer, as the detrimental consequences are often associated to desirable high operational parameters, such as rate and pressure transverse in producing well.Design/methodology/approachA variety of early models for predicting pressure transverse in gas wells were based on steady state flow equation that did not consider time factor, which results in inaccuracy at early production time. Some of the early investigators overlooked the effect of the solid on the pressure transverse phenomena in a gas well. Hence, there is a need for developing a model for estimating pressure transverse at all times in solid–gas well. This study presents an equation for pressure drop in flowing vertical well without neglecting any term in the momentum equation by the inclusion of accumulation and kinetic term.FindingsThe solution of the resulting differential equation gives functional relationship between solid–gas flow rates and pressure at any point in flowing well at any given production time. The results show improvement over previous studies, as the assumptions previously neglected were all considered.Originality/valueA more realistic result that includes the initial unsteadiness phenomenon is obtained; hence, predicting pressure transient at any given production time has been established for both gas that flows along with solid particles and gas without particles. At the onset of production, the effect of all possible wellbore pressure losses is highly pronounced and decreased as the production time increases. The newly developed model, however, can be used at all depths. The effect of using the Sukkar and Cornell model is extremely adverse for the calculation of other parameters, such as flow rate, and carrying out economic analysis.

Modeling competing hydraulic fracture propagation with the extended finite element method

We present an extended finite element framework to numerically study competing hydraulic fracture propagation. The framework is capable of modeling fully coupled hydraulic fracturing processes including fracture propagation, elastoplastic bulk deformation and fluid flow inside both fractures and the wellbore. In particular, the framework incorporates the classical orifice equation to capture fluid pressure loss across perforation clusters linking the wellbore with fractures. Dynamic fluid partitioning among fractures during propagation is solved together with other coupled factors, such as wellbore pressure loss ( $$\Delta p_w$$ ), perforation pressure loss ( $$\Delta p$$ ), interaction stress ( $$\sigma _\mathrm{int}$$ ) and fracture propagation. By numerical examples, we study the effects of perforation pressure loss and wellbore pressure loss on competing fracture propagation under plane-strain conditions. Two dimensionless parameters $$\Gamma = \sigma _\mathrm{int}/\Delta p$$ and $$\Lambda = \Delta p_w/\Delta p$$ are used to describe the transition from uniform fracture propagation to preferential fracture propagation. The numerical examples demonstrate the dimensionless parameter $$\Gamma $$ also works in the elastoplastic media.

Fully coupled simulation of multiple hydraulic fractures to propagate simultaneously from a perforated horizontal wellbore

In hydraulic fracturing process in shale rock, multiple fractures perpendicular to a horizontal wellbore are usually driven to propagate simultaneously by the pumping operation. In this paper, a numerical method is developed for the propagation of multiple hydraulic fractures (HFs) by fully coupling the deformation and fracturing of solid formation, fluid flow in fractures, fluid partitioning through a horizontal wellbore and perforation entry loss effect. The extended finite element method (XFEM) is adopted to model arbitrary growth of the fractures. Newton’s iteration is proposed to solve these fully coupled nonlinear equations, which is more efficient comparing to the widely adopted fixed-point iteration in the literatures and avoids the need to impose fluid pressure boundary condition when solving flow equations. A secant iterative method based on the stress intensity factor (SIF) is proposed to capture different propagation velocities of multiple fractures. The numerical results are compared with theoretical solutions in literatures to verify the accuracy of the method. The simultaneous propagation of multiple HFs is simulated by the newly proposed algorithm. The coupled influences of propagation regime, stress interaction, wellbore pressure loss and perforation entry loss on simultaneous propagation of multiple HFs are investigated.

A New Approach for Optimization of Long-Horizontal-Well Performance

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18372, “A New Approach for Optimization of Long-Horizontal-Well Performances,” by Abdullah Al Qahtani, Hasan Al Hashim, and Hasan Al Yousef, King Fahd University of Petroleum and Minerals, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Copyright 2015 International Petroleum Technology Conference. Reproduced by permission. Initially, it was believed that a horizontal well should be drilled with as much length as possible. However, field experience and flowmeter surveys in long horizontal drainholes revealed that the frictional pressure loss in the wellbore is an important factor hindering the full use of the entire length of the horizontal well. This paper presents a new approach to maximize the use of the full length of long horizontal drainholes. Introduction Horizontal-well drilling allowed the drilling of different well architectures and made it possible to offset well costs and productivity limitations. Intuitively, drilling longer wells will maximize exposure to the producing formation and yield higher flow capacity. Paradoxically, however, some wells were drilled longer than the optimal horizontal-section length and the extra length did not yield additional flow. Therefore, it is important to determine the optimal horizontal-section length that would achieve flow contribution along the whole section. Experience has revealed that long horizontal wells suffer from frictional pressure losses. This fact is exacerbated in the presence of highly productive formations; these would require low pressure drawdowns that may well be similar to the frictional pressure losses, which would therefore hinder wellbore flow ingress. Thus, some horizontal wells are equipped with downhole flow-choke systems to optimize well productivity. Finite-Conductivity Horizontal Wells Horizontal wells are initially deemed to be infinite-conductivity wellbores; this thesis was made on the basis of the fact that the magnitude of the pressure drop in the wellbore is negligible. Practically speaking, however, production data proved otherwise; frictional pressure losses in horizontal wellbores hinder flow influx to different degrees along the horizontal section. This issue is of great importance under conditions in which the magnitude of the pressure drop in the wellbore is small when compared with the magnitude of the pressure drop in the reservoir. Therefore, given the fact that horizontal wells are often proposed and justified on the premise that high production rates can be obtained by small reservoir pressure drops, and the fact that flow developed at reasonably high production rates should cause increased wellbore pressure losses, the use of the infinite-conductivity assumption for horizontal wells may not be valid.

A Model for Predicting Productivity of Multi-Staged Fractured Horizontal Wells in Ultra-Low Permeability Tight Gas Reservoirs

Based on the equivalent radius model and superposition potential, a productivity model for ultra-low permeability tight gas reservoirs was developed, which considered the influence of the threshold pressure gradient and the variable mass flow in fractures, and pressure loss inside the wellbore. With examples for capacity sensitive factors are analyzed. The results show that the threshold pressure gradient must be accounted to evaluate the productivity in ultra-low permeability tight gas reservoirs; after considering wellbore pressure loss; close toe fractures inflow velocity segment has been reduced; the larger matrix permeability, the greater the optimum fracture conductivity; When the number of fracture is more, the greater the impact on the capacity of the fracture angle. The research results provide a scientific basis for the design of multi-fractured horizontal wells in the ultra-low permeability tight gas reservoirs.

Modeling of Wellbore Overall Heat Transfer in Circulation

Heat is transferred between the fluid and the surroundings in the wellbore. Quantitative knowledge of wellbore heat transfer is important in drilling and production operations. A new model of wellbore heat transfer using finite element analysis is developed in this study. This solution assumes the heat transfer in the wellbore is steady state and only happens in radial direction. The model considers heat gained due to wellbore pressure loss in circulation, which is more accurate in temperature calculation. The overall heat resistance in the wellbore is analyzed, taking into account the film heat transfer coefficients difference between the tube and the annulus. Previous literature has been reviewed to determine the correlation which can be used in the model.

Modeling Productivity Index for Long Horizontal Well

Horizontal wells have become a popular alternative for the development of hydrocarbon fields around the world because of their high flow efficiency caused by a larger contact area made with the reservoir. Most of the analytical work done in the past on horizontal productivity either assumed that the well is infinitely conductive or the flow is uniform along the entire well length. The infinite conductive assumption is good only when the pressure drop in the wellbore is very small compared to the drawdown in the reservoir otherwise the pressure drop in the wellbore should be taken into account. In this paper, an improved predictive model that takes into account the effect of all possible wellbore pressure losses on productivity index of long horizontal well was developed. Results show that the discrepancies in the predictions of the previous models and experimental results were not only due to effect of friction pressure losses as opined by Cho and Shah but may also be due to all prominent pressure losses such as kinetic change and fluid accumulation experienced by the flowing fluid in a conduit. The effect is most pronounced at the early production time where initial transience at the onset of flow is experienced.

Integrated Approach To Optimize Material Selection for High-Rate Gas Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12503, "Integrated Approach To Optimize Material Selection for North Field High-Rate Gas Wells," by W.A. Sorem, RasGas Company; E.J. Wright and J.L. Pacheco, ExxonMobil De vel opment Company; and D.A. Norman, ExxonMobil Upstream Research Company, originally prepared for the 2008 In ter national Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed. The RasGas Company North field wells typically have a true vertical depth of 9,000 ft with a sail angle up to 70º. The combination of 7-in. mono-bore and 9 5/8-in. big-bore wells is designed to handle hydrogen sulfide (H2S) and carbon dioxide (CO2) corrosion, hydrochloric acid (HCl) stimulation, and environmental cracking. The wells must accommodate high flow rates and through-tubing intervention. The full-length paper describes the technical development of an optimized operational envelope for L-80 carbon-steel tubulars for these high-rate gas wells in Qatar. Introduction The North field is offshore to the northeast of Qatar in the Arabian Gulf. It is the world's largest nonassociated-gas field, with reported reserves of more than 900 Tcf. The sour, abnormally pressured natural gas is contained in the massive Khuff carbonate formation. RasGas currently has 11 offshore platforms in the North field. Two different types of production wells have been used on these platforms. The first type is a 7-in.-monobore well with 7-in. tubing and liner made of L-80 carbon steel. The second well type is referred to as the 9 5/8-in. optimized big-bore (OBB) well comprising 9 5/8×7 5/8-in. tapered production tubing made of L-80 carbon steel and a 7-in. liner made of Alloy 28 corrosion-resistant alloy (CRA). More than 60 9 5/8-in. OBB wells have been drilled and completed to date. The wells are more than of 9,000 ft deep with deviations from vertical of as much as 70°. Well deliverability for the 9 5/8-in. OBB wells is greater than for the 7-in. monobore wells, and on the basis of reservoir modeling, it was determined that the target project production could be achieved with 25% fewer wells. At equivalent production rates, the 9 5/8-in. OBB wells have less wellbore pressure loss, resulting in an extension of the plateau life without surface compression. All of these wells must be designed to handle H2S and CO2 corrosion, HCl stimulation, and environmental cracking. All of the acid used to stimulate these wells contains corrosion inhibitors to mitigate corrosion in the tubing and liners during acid stimulation. The tubular materials are designed to withstand the corrosive production environment on their own without chemical inhibition. Early in the design phase of the 9 5/8-in. OBB wells, the use of CRAs was considered for both the tubing and the 7 in. liner. However, it was determined that CRA materials could not be fabricated (on a commercial scale) to 9 5/8-in. diameter in usable lengths because of tubular-mill manufacturing limitations, so carbon steel would have to be used to enable the 9 5/8-in. OBB production advantages.

Application of a Thermal Simulator with Fully Coupled Discretized Wellbore Simulation to SAGD

Abstract This paper discusses the implementation of a discretized wellbore simulator fully implicitly coupled with the grid cells in a thermal compositional simulator. The computation of pressure losses due to multiphase frictional effects and flow regimes in the wellbore cells is handled with the Beggs and Brill correlation, but the formulation is general enough to use with any other correlation. Wellbore configurations, such as partial or complete tubing in casing, uninsulated/insulated tubing, partial or complete casing perforations, and variations in skin damage along the well, can be modelled. The resulting simulator has been applied to simulate circulating startup in SAGD processes with steam trap control. The model's calculated horizontal wellbore pressure losses compare favourably with a process simulator. The simulator SAGD oil rates for 2D cases with steam trap control match published results from another simulator. The simulator can be used for SAGD well design to redirect tubing and annular flows to try to affect steam chamber development. The effects of tubing insulation and pressure drop are shown in 3D cases. The simulation cases have reasonable execution times, thus showing the efficiency of the coupled wellbore model. Introduction Most conventional simulators model well flow as source-sink terms. For a well with a long perforation interval, several grid cells along the perforation path of the well will be used as well locations and a source-sink term allocated to each well location grid cell. The total well rate will then be the sum of the individual source-sink terms allocated to the well. It will be assumed that there is infinite conductivity between the well locations; that is, there is no frictional pressure loss between the source-sink terms. Thus, for horizontal wells, the wellbore pressure will be assumed to be equal among all the locations. For vertical wells, some simulators will compute an average density based on entering fluid from the locations, and use this to compute a wellbore pressure gradient based on the vertical depth of the various locations. This approach is simple, quick, and sufficient for most problems in conventional recovery involving vertical wells. There is no consideration of frictional losses, and what happens in the pipe or casing is ignored. When crossflow occurs in the tubing, simplifications have to be made to compute crossflow, based on averaged wellbore fluid contents. In the Steam Assisted Gravity Drainage (SAGD) process, a long horizontal well is used to inject steam, and a lower long horizontal well is used to produce hot oil draining from the resulting steam chamber. As sometimes the cold oil is immobile, it is necessary to circulate steam in both the upper horizontal injector and lower horizontal producer to preheat the oil before communication of temperature and pressure can be achieved between the well pairs. This is accomplished by using a tubing string inside the casing. To accurately model these startup conditions, it is not possible to use source-sink terms. If source-sink terms are used, the startup heating phase is modelled using heat injector source-sink terms at the well locations.

Evolution of a High Near- Wellbore Pressure-Loss- Treatment Strategy

This article is a synopsis of paper SPE 63029, "The Evolution of a High Near-Wellbore Pressure-Loss-Treatment Strategy for the Australian Cooper Basin," by Geoffrey A. Roberts, SPE, and Simon T. Chipperfield, SPE, Santos Ltd., and William K. Miller II, SPE, NSI Technologies Inc., originally presented at the 2000 SPE Annual Technical Conference and Exhibition, Dallas, 1-4 October.