Segmentally variable density perforation optimization model for horizontal wells in heterogeneous reservoirs

The accuracy of the production forecast of fractured horizontal well not only affects the result of the optimum design and economic evaluation, but also affects the success and effectiveness of the fractured horizontal well. Therefore, it is quite essential to present new models fit for the actual seepage phenomenon to calculate the fractured horizontal well production. Multi-fractures propped when the horizontal well is fractured. But due to the stress difference along the horizon well and the restriction of the fracturing technology, the formed factures are different in length, conductivity, azimuth angle and so on. Moreover, during the production process, the fractures mutual disturbance makes the prediction of fractured horizontal well become more difficult, This paper combines the shape of formed fractures and the fluid peculation mechanism together to present a new model, which is based on superposition theory to predict the fractured horizontal well production The new model considers the effect of the fracture number, fracture length, fracture interval, the symmetry of the fractures, azimuth angle and conductivity We applied the new model to predict the productions of three fractured horizontal wells in China; the accordance is very well, up to 97.4%. Introduction Horizontal well can greatly increase the contact area of the well bore and the pay zone, so it is an important means to exploit the low permeability oil reservoir and to enhance the production and ultimate recovery. Sometimes due to the low permeability, large seepage resistance, low connectivity in the low permeability reservoir, the production of the horizontal well is still low. Therefore, it is necessary to frac the horizontal well to enhance the production. The accuracy of the fractured horizontal well production not only affects the result of the optimization design and economic evaluation, but also affects the success and effectiveness of the fractured horizontal wells, so it is vital to calculate the production exactly. According to related literature home and aboard, we found that it is a difficult problem to predict fractured horizontal well production. Soliman[1] et al researched the production model for the horizontal well with finite conductivity fracture in an infinite thick oil reservoir, and drawed the conclusion that larger conductivity can overcome the additional pressure drop caused by the linear influx flow. Li [2] et al presented a stable production model for the fractured wells. When the fracture plane is perpendicular to the well bore, he separated the n fractures into N flowing areas, and the each fracture is the center of the every area, supposing that each fracture produced only in its own area, this method didn't consider the fracture disturbance. B.Guo's [3] model is still fit for the stationary state flow, in this method, it should first to calculate one single fracture production, and then multiply single fracture production with N to get the N fractures production. Clearly, this method still didn't consider the fractures disturbance. Guo Jianchun[4] et al based on the fracture-reservoir system two dimension oil-water two phases model to simulate the production of horizontal wells, and combine the economic evaluation to presented an fractures optimum model for the fractured horizontal well.

Downhole temperature measurements either by permanent sensors or temporarily conveyed tools provide information that has been used in many production diagnosis applications. This paper presents a study that correlates the temperature behavior to the flow profile in a multi-stage fractured horizontal well. The ultimate goal is to interpret well performance and to optimize fracture treatment design from monitored temperature data. This study has developed flow and thermal models for horizontal wells with transverse fractures. The system was divided into a horizontal wellbore and a reservoir having multiple fractures in the study. The wellbore flow and thermal model were formulated based on mass, momentum and energy balance. Numerical reservoir simulation was adopted for the reservoir flow problem, and the reservoir thermal model was formulated by a transient energy balance equation considering viscous dissipation heating and temperature variation caused by fluid expansion besides heat conduction and convection. In the reservoir system, the primary hydraulic fractures perpendicular to the horizontal well were modeled with thin grid cells explicitly, and the fracture network around the horizontal well was modeled as an enhanced permeable zone with respect to the unstimulated matrix permeability. The reservoir grids between two fractures were logarithmically spaced to capture transient flow behavior. The reservoir flow and thermal model was coupled with the wellbore model to predict the temperature distribution in a horizontal wellbore. The results of the model show two main mechanisms in this thermal problem: heat conduction by formation heating/cooling effects at non-perforated zones, and wellbore fluid mixing effects with reservoir inflow at fracture locations (fluid entry points). The examples in the paper illustrated that the models can be used to predict temperature profiles in stimulated horizontal wells for identical or non-identical transverse fractures. Sensitivity studies were performed to evaluate the influences of fracture conductivity and half-length on temperature behavior in the defined system. The results indicate that the wellbore temperature is primarily sensitive to fracture geometry (fracture half-length). It is possible to interpret the fracture geometry using temperature data after the flow rate is stabilized after certain period of production. In addition, wellbore temperature is also sensitive to fracture conductivity. However, the signal of high fracture conductivity diminishes, and after the surface flow is stabilized, the signal might not be identified by temperature measurement. Real time temperature data measurement is helpful for the evaluation of fracture conductivity.

The productivity calculation model of perforated horizontal well and optimization of inflow profile

Summary Stinger-completion technology is simple to operate and low cost, which can achieve good results in stable oil production by controlling water cut in a bottomwater reservoir. However, most previous studies of stinger completions took place in homogeneous reservoirs and are not equipped to deal with the multipoint watercresting breakthrough caused by fractures or permeability contrast in a heterogeneous bottomwater reservoir. A new improvedstinger- completion (ISC) semianalytical coupled model of reservoir and wellbore flow is established in this article, which considers the impacts of well trajectory, permeability distribution, formation damage caused by drilling and completion, and variable mass flow in a horizontal wellbore. By discrete numerical calculation of the new model, pressure, inflow, and water-cresting profiles can be acquired, and consequently, a design method of ISC is also proposed to be used successfully in a heterogeneous bottomwater reservoir for stable oil production by water-cut control and by optimizing the structure, length, and diameter of the stinger. The successful field application of ISC in the LU-X horizontal well also confirms the feasibility and effectiveness of ISC.

In The giant Hassi Messaoud Oilfield, horizontal and short radius wells are mostly crossing more than one layer and many of them are crossing two compartments, where gas breakthrough is occurring in some layers and compartments. There are three main objectives of the present study. Firstly, is to improve oil productivity while reducing the gas breakthrough production. The second aim is to preserve the accumulated injected gas gained over decades of time. The third objective is to maintain the miscibility conditions within some injection gas patterns as initially planned. Two principles have been used to complete the study. The first one is the composite inflow performance relationship "IPR" between oil and gas reservoir systems crossed by a horizontal well, whereas the second option is a smart well completion implementation and modeling of horizontal wells crossing two layers having two reservoir pressures due to gas injection wells. Three categories of results have been obtained. Primarily, well modeling and optimization of horizontal well without smart completion, and secondly an implementation of intelligent completion model for horizontal well crossing different intervals in gas breakthrough. Some scenarios of optimizations have been done based on the available input of well. Finally, it will be possible to maintain the miscibility conditions within a gas injection pattern using the intelligent completion option.

Study on modified maximum extension length prediction model for horizontal wells considering differential sticking

Flow simulation for a horizontal well with slotted screen and ICD completions based on the wellbore–annulus–reservoir model

Drilling horizontal wells to accelerate production and increase recovery efficiency of oil and gas has now become common. With the increasing number of wells, transient well tests have been conducted in many wells with different geological settings. In this paper, we present a number of analytical models for horizontal wells with multiple fractures in homogeneous and laterally composite reservoirs. These solutions are applicable to finite-conductivity transverse fractures, and infinite-conductivity transverse and longitudinal fractures. They may also be used for the fractured reservoirs where the wellbore intersects with multiple fractures. We examine the pressure behavior of horizontal wells with single and multiple fractures in homogeneous systems. It is shown that the wellbore cannot be neglected in the modeling of horizontal wells with fractures unless the fracture conductivity is high. If the fracture permeability (conductivity) variations in different zones are moderate, compared to the formation permeability, the multiple fractures have almost no effect on the pressure behavior of the system; the horizontal well dominates the system's pressure behavior. If the conductivities are high, the intersected fractures will dominate the behavior of the system at early times. It is also shown that multiple finite- and infinite-conductivity transverse fractures may exhibit multiple linear flow regimes before the onset of the first horizontal well radial flow regime.

Length and profile shape of horizontal section of the production well is one of the main issues in the justification of horizontal well completion. Justified choice of horizontal well completion and profile design is based on the main objectives: provide high initial rate, maximize the cumulated gas and condensate production, reduce the risk of well drilling and completion, extend a period with water free production, hence resulted in the maximum NPV. The main factors that influence the choice of horizontal well profile are the geological structure of the productive formation, its reservoir properties, the location of formation fluid contacts, formation anisotropy, the ratio of vertical and horizontal heterogeneity. In this paper we investigate the influence of mentioned geological factors on the choice of horizontal well profile. Various profiles of horizontal wells- directional, horizontal and U-shaped have been considered for gas condensate reservoirs. The analysis was conducted on the basis of hydrodynamic modeling Eclipse 300 using a function of multi-segment well. After choice of the optimal length for the horizontal section of the well, a simulation was performed. Also there was a comparison of the performance for directional and U-shaped horizontal wells with the same length. During comparing the well performance well productivity, cumulative gas and condensate production, inflow profiles, the conditions of liquid removing from well bottom of were evaluated. Sensitivity evaluation of the optimal profile selecting to the reservoir permeability and its anisotropy was performed. It helps to take into account the effect of uncertainty on the performance of the well. Selecting a profile of the horizontal section of the well is one of the main issues in the design and affects not only the final gas and condensate recovery, but also helps to clarify the geological structure formation during logging, and enable the development of all productive layers, reduce the risk of complications during the operation. Structural features of horizontal wells unlike allow to obtain vertical flow rates several times superior performance of vertical wells. And the increase in horizontal wells is provided not by increasing the drawdown, and by increasing the filter surface. Productivity is limited in the vertical wells of the reservoir reveals the thickness, whereas the thickness of a predetermined value for the formation and drawdown -the geometrical parameters of the liner and, consequently, horizontal wells depends on the length of the horizontal wellbore. The horizontal wellbore completion may be regarded as an effective method for production of hydrocarbons, and as a method of stimulation. Engineering and technology horizontal drilling, completion fluid, their performance, conduct work under stimulation to them, economic indicators drilling and operation of horizontal wells devoted several thousand research. At the same time question the justification of the optimal design and the length of the gas and gas condensate wells are virtually unexplored. Studies on this topic have been done by Z.S. Aliyev, V. Sheremet and V.A. Chernykh. Z.S. Aliyev in one of his works says that the only way to study the optimal design of horizontal gas wells drilled in inhomogeneously layered strata, is a numerical solution to this problem through the creation of geological and mathematical models of fragments of such deposits and the joint solution of unsteady, multidimensional, multiphase and multicomponent filtering the horizontal trunk with the equation of motion with a variable flow rate of the mixture along the length of the barrel. In this paper we provide a rationale for completing horizontal wells for specific geological conditions of the N-th gas condensate field located in the east of the autonomous area.

A horizontal well usually yields a high rate through its long perforation interval, resulting in a large frictional pressure drop that is believed to reduce the well productivity. Unlike conventional horizontal well methods which consider the horizontal section only, the proposed model also includes the vertical section of the well and the surface facility from the well head to the GOSP. The hydraulics model was validated stage-by-stage by various known solutions, and then applied to a high rate well. It was found that the effect of frictional pressure drop on oil rate was not as pronounced as suggested by analytical methods, or some numerical simulation studies. In summary, the pressure drop in the vertical section of the horizontal well plays an especially important role in deciding how much fluid can be produced. Therefore, it is recommended to be an integral part of horizontal well models.

With the advancement of completion technology for horizontal wells in bottom water reservoirs, Autonomous Inflow Control Devices (AICDs), which have achieved good results in recent years, have been widely used in the oil fields of the eastern South China Sea. Although some mathematical methods can be used to predict the production performance of horizontal wells, there is no dynamic prediction method for the production performance of horizontal wells completed with AICDs. In this work, a mathematical model of porous flow in the reservoir, nozzle flow in the AICD, and pipe flow in the horizontal well is established, and then a new model is presented for predicting the dynamic performance of horizontal wells completed with AICDs in bottom water reservoirs. The new coupling model is compared with two horizontal wells completed with AICDs in the bottom water reservoirs of the eastern South China Sea, and the results indicate that the accuracy of the new model is sufficiently high to provide theoretical support for the further prediction of horizontal wells in the eastern South China Sea.

Properties of gas condensate reservoirs are particularly difficult to study due to the composition and phase changes of light components that occur during the reservoir depletion. At the first stage of their discovery, these reservoirs behave like gas reservoirs during depletion. Once the dew point pressure is reached at reservoir conditions of pressure and temperature a retrograde condensation phase develops in the reservoir. Liquid condensation in the formation can result in severe loss of well deliverability and therefore of gas and condensate recovery, which will certainly lead to a loss of income. In this study, the performance of horizontal wells and vertical wells in Gas condensate reservoirs is investigated under various depletion schemes. The expected low horizontal well drawdown pressure, compared to vertical well for the same flow rate, considerably reduces retrograde condensation. A reservoir simulator is used to compare liquid saturation profiles in the case of horizontal and vertical wells in Gas condensate reservoirs. The influence of the horizontal well length section and reservoir thickness on horizontal well productivity, and condensate recovery were also simulated. Another factor investigated in this study is the effect of drilling a horizontal well in a Gas condensate reservoir that has already been developed by vertical wells. To illustrate the productivity increase due to the use of horizontal wells in gas condensate reservoirs, Djebel Bissa field data are presented and discussed using a compositional single well model (VIP simulator). The main results of this investigation are: Because pressure drawdown is smaller for a horizontal well than that for a vertical well, the problems related to the liquid deposit can be reduced by the use of horizontal wells. Layers of value of kh contains the most liquid accumulations.

Horizontal wells can have very complex flow geometries, in part due to interaction between the main flow stream and the influxes along the wellbore, and also due to completion type. In this study, the flow behavior in horizontal wells with a single perforation and with multiple perforations of perforation densities equivalent to 1, 2 and 4 shots per foot were investigated. A new test facility was designed and constructed to simulate single phase liquid flow in horizontal wells. Experiments were conducted with Reynolds numbers ranging from 5,000 to 60,000 and influx to main flow rate ratios ranging from 1/5 to 1/100 for the single injection case and from 1/100 to 1/2000 for the multiple injection case and for the no influx case. A general horizontal well friction factor expression was developed using the principles of conservation of mass and momentum. Horizontal well friction factor correlations were developed by applying experimental data to the general friction factor expressions. It was observed that the friction factor for a perforated pipe with fluid injection can be either smaller or greater than that for a smooth pipe, depending on influx to main flow rate ratios. The proposed friction factor correlation can be used in any horizontal well model which considers pressure variation along the wellbore. Introduction The most commonly used assumptions in studying horizontal well production behavior are: infinite conductivity, and uniform influx. Infinite conductivity assumes no pressure drop along a horizontal well, and uniform influx assumes that the influx from the reservoir is constant along a horizontal well. It has been argued in the literature that the infinite conductivity wellbore assumption is adequate for describing flow behavior in horizontal wells. Although this may be a good assumption in situations where the pressure drop along the horizontal section of the wellbore is negligible compared to that in the reservoir, it is also reasonable to expect the friction and acceleration effects to cause noticeable pressure drops in long horizontal wellbores. In a horizontal well, depending upon the completion method, fluid may enter the wellbore at various locations along the well length. The distance between perforations may not be sufficient to achieve a stabilized velocity profile, and this may lead to different pressure behavior than for fully developed flow. The pressure distribution in a horizontal well can influence the well completion and well profile design, as well as having an impact on the production behavior of the well. Therefore, both the pressure drop vs. flow behavior along the well and the relationship between the pressure drop along the well and the influx from the reservoir need to be understood. Flow behavior in porous wall pipes or plates has been studied by several investigators in other disciplines. Although they provide useful information to the study of horizontal well flow behavior, the results can not readily be applied in the petroleum industry. The petroleum industry started to investigate horizontal wellbore hydraulics in the late 1980's. Investigators conducted analytical or experimental studies to investigate different aspects of horizontal well flow behavior. A friction factor correlation for horizontal wellbores was proposed by Asheim et al. which includes accelerational pressure losses due to continuous fluid influx along the wellbore. However, the literature survey reveals that experimental data are limited and theoretical studies are inconclusive for predicting frictional pressure loss in horizontal wells. In this study, an experimental and theoretical investigation of the flow behavior in a horizontal pipe with fluid injection from a single injection point in the pipe wall and from multiple injection points in the pipe wall with perforation densities equivalent to 1, 2 and 4 shots per foot has been conducted. New correlations based on acquired experimental data were developed for the prediction of friction factors in a horizontal wellbore. Model Development A general model was developed to predict horizontal well friction factors. P. 603

Horizontal wells have revolutionized hydrocarbon production by enhancing recovery efficiency and reducing environmental impact. This paper presents an enhanced Black Oil Model simulator, written in Visual Basic, for three-dimensional two-phase (oil and water) flow through porous media. Unlike most existing tools, this simulator is customized for horizontal well modeling and calibrated using extensive historical data from the South Rumaila Oilfield, Iraq. The simulator first achieves a strong match with historical pressure data (1954–2004) using vertical wells, with an average deviation of less than 5% from observed pressures, and is then applied to forecast the performance of hypothetical horizontal wells (2008–2011). The results validate the simulator’s reliability in estimating bottom-hole pressure (e.g., ±3% accuracy for HRU1 well) and water–oil ratios (e.g., WOR reduction of 15% when increasing horizontal well length from 1000 m to 2000 m). Notably, the simulator demonstrated that doubling the horizontal well length reduced WOR by 15% while increasing bottom-hole pressure by only 2%, highlighting the efficiency of longer wells in mitigating water encroachment. This work contributes to improved reservoir management by enabling efficient well placement strategies and optimizing extraction planning, thereby promoting both economic and resource-efficient hydrocarbon recovery.

Predicting accurate inflow pressure and flow profile of horizontal laterals is one of the biggest impediments in achieving their optimum performance. Reservoir simulators are capable of simulating flow in the reservoir up to the fluid entry points in the well reasonably well. Wellbore simulators can simulate flow from the fluid entry points up to the surface delivery system. The integrated system can be simulated numerical reservoir simulators adequately assuming a single point fluid entry to the well. However, accurate foot by foot prediction of pressure and flow profile at the reservoir/well interface of long horizontal wells is a challenge. Some simulators attempt to simulate this detailed inflow profile using some simplified approach. A few semi-analytical modeling approach is also available in the literature. They use average parameter values in their calculation. These simplifying assumptions result in less than accurate inflow profile prediction to the extent that they are inadequate for some design optimization studies.In this paper we describe coupling of a 3-D numerical reservoir simulator with a wellbore simulator in a simple manner which is capable of predicting a detailed inflow profile along long horizontal wells. Flow and pressure along the laterals are iterated between the simulators at each point of interface until they converge. This convergence is repeated at desired time intervals ultimately resulting in a fully converged integrated reservoir-wellbore simulation with the detailed and accurate inflow profile. The algorithm was initially tested manually and later automated. Results of the work is presented along with an application (designing Inflow Control Devices) aimed at achieving uniform flow profile along horizontal laterals. This is a powerful capability which will enable us optimize horizontal completions to the extent which was not possible before.