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

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.

Horizontal well technology is one of the major improvements in reservoir stimulation. Planning and execution are the key elements to drill horizontal wells successfully, especially through depleted formations. As the reservoir has been producing for a long time, pore pressure declines, resulting in weakening hydrocarbon-bearing rocks. Drilling issues such as wellbore stability, loss circulation, differential sticking, formation damage remarkably influenced by the pore pressure decline, increasing the risk of losing part or even all the horizontal interval. This paper presents an extensive review of the potential issues and solutions associated with drilling horizontal wells in depleted reservoirs. After giving an overview of the depleted reservoir characteristics, the paper systematically addresses the major challenges that influence drilling operations in depleted reservoirs and suggests solutions to avoid uncontrolled risks. Then, the paper evaluates several real infill drilling operations through depleted reservoirs, which were drilled in different oilfields. The economic aspect associated with potential risks for drilling a horizontal well in depleted reservoirs is also discussed. The most updated research and development findings for infill drilling are summarized in the article. It is recommended to use wellbore strengthening techniques while drilling a horizontal well through highly depleted formations. This will allow using higher mud weight to control unstable shales while drilling through the production zone. Managed Pressure Drilling should be considered as the last option for highly depleted formations because it will require a greater level of investment which is not going to have a superior rate of return due to the lack of high deliverability of the reservoir. Using rotary steerable systems is favored to reduce risks related to drilling through depleted formations. Precise analysis of different drilling programs allows the drilling team to introduce new technology to reduce cost, improve drilling efficiency and maximize profit. It is the responsibility of the drilling engineer to evaluate different scenarios with all the precautions needed during the planning stage to avoid unexpected issues. The present market conditions and the advancement in technologies for drilling horizontal wells increase the feasibility of producing the depleted reservoirs economically. This paper highlights the challenges in drilling horizontal wells in highly depleted reservoirs and provides means for successfully drilling those wells to reduce risks while drilling

Horizontal drilling is one of development strategies to optimize the oil recovery, especially in a mature field. Horizontal well can reduce water and gas coning and prevent the pressure drop around the well bore, therefore the oil recovery can be increased. Radioactive source in Logging While Drilling (LWD) tools is used for X-42 horizontal drilling well but stuck problem that occurs during the drilling operation can be caused by differential sticking or failure hole cleaning. High angle inclination in horizontal well certainly increases the difficulty of retrieval job. As a company regulation, the radioactive source should be retrieved before continuing the efforts to free the drill string. The wireline has agreed to help the radioactive retrieval but this operation should be done in 81° of inclination. Then, it will need a thrusting force to facilitate the bottomward movement of the assembly. Two attempts of retrieval with wireline are made before they bring up the idea of using sucker rod as the replacement a wireline cable. This paper explains how the unconventional radioactive retrieval method with sucker rod as the alternative of wireline is more reliable to retrieve the radioactive fish especially in horizontal wellbore which technically has a very high inclination and 3D profile which the tool need a thrusting force to push the fishing tool assembly to the bottom.

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.

As operators reduce spending on exploration, more wells with increasing complexity are being drilled in mature fields. As the well complexity increases, a dilemma often occurs over how to address borehole stability requirements while mitigating the risks of shale instability, differential sticking or mud losses due to high differential pressures. These wells may have little or no operating margin between the pore pressure and formation breakdown. High mud weight may be required to prevent shale collapse. Options tend to be limited to accepting the drilling risks or setting a contingency casing string—both very expensive choices in terms of equipment and lost time. Downhole losses and differential sticking occur because the drilling fluid hydrostatic pressure is higher than the formation pressure, a situation referred to as ‘overbalanced pressure’ while drilling through formations that are fractured, under pressured, cavernous or highly permeable. Traditionally, the wells in these types of fields experience some or all of these drilling problems. Wells drilled through the interbedded shale and sandstone Barik formation usually encounter severe wellbore stability issues that result in increased drilling time and the possibility of side tracks. Wellbore instability occurs because the Barik formation requires a high fluid density to stabilize the shale sections due to the depleted, low-pressure sandstone sections. Wells drilled in the Barik formation have been drilled with an advanced invert emulsion fluid. These wells experienced wellbore instability and differential sticking, resulting in significant non-productive time (NPT). One of the limitations of bridging wells with traditional materials is the impact these materials may have on rheological properties and the generally poor performance they demonstrate with respect to wellbore stability at overbalance pressures greater than 2,000 psi. A water-based fluid with an optimized bridging and sealing system was custom-designed using proprietary software and based on deformable nanotechnology material with synthetic carbon-based additives. This combination of additives provides a wide particle size distribution range to cover the micro-fractures (< 200 nanometers) and the macro-fractures (>10 microns). This bridging system comes in a single sack, which helps reduce transportation costs, logistics, rigsite footprint and minimises manual handling. This was the first application of water-based mud to drill in the field, and the customized bridging and sealing package was successful in sealing the Barik sandstone, allowing the horizontal well to be drilled to planned depth without NPT, despite the formation being subjected to high overbalance pressures greater than 5,600psi. The bridging and wellbore strengthening properties of the custom-designed water-based fluid prevented instability of the shale by sealing the formation, delivering excellent wellbore stability while simultaneously sealing the sandstone and preventing differential sticking. This approach resulted in a significant reduction in NPT compared to the previous attempts.

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.

Wellbore stability model for horizontal wells in shale formations with multiple planes of weakness

In order to make extended-reach drilling (ERD) of deepwater cost-competitive and obtain the maximum reservoir contact, dual-gradient drilling (DGD) technology is more and more used in offshore drilling. In this study, a method to predict the maximum measured depth (MMD) of the offshore horizontal well by DGD method in deepwater is presented. The prediction model is established based on the dynamic pressure balance of bottom hole. Two prediction models of offshore horizontal well's MMD by subsea mudlift drilling (SMD) method and hollow glass spheres (HGS) method are analyzed and established respectively. Moreover, effects of flow behavior index, consistency coefficient, drilling fluid density and ROP on these predicted MMDs with two DGD methods are analyzed. Finally, an offshore horizontal well in the South China Sea is analyzed. Some optimization measures are also put forward to obtain higher MMD and maximize reservoir contact. The study shows that there is a decrease of the predicted MMD as the flow behavior index, consistency coefficient and ROP are increased. Moreover, effects of drilling fluid density on the predicted MMD with different drilling methods are also analyzed. It shows that the ERW's MMD first increases and then decreases with the increase in drilling fluid density. It also shows that DGD method is conducive to expanding the MWW of horizontal well in deepwater. This work provides a practical tool for predicting the horizontal well's MMD of DGD in deepwater and achieving greater MMD. The study is significant to maximize reservoir contact and obtain good economic benefits of oil and gas development in deepwater.

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.

A study dealing with formation damage and damage control for horizontal wells drilled in the Shengli and Dagang (both in East China) sandstone formations is reported in this paper. The factors influencing the productivity of horizontal wells were quantitatively analyzed. The results show that formation damage is an important factor affecting productivity, compared with other factors, such as reservoir thickness, horizontal well length and anisotropy ratio of permeability, for the low permeable formations with permeabilities less than 80 md. It was also found that the effect of formation damage on production rate is constantly much higher for a horizontal well than that for a vertical well drilled in the same formation under the similar drilling conditions. To minimize the formation damage during horizontal drilling, three less-damaging drilling and completion fluids (a newly developed polymer mud, SN-1 oil emulsion mud and MMH mud) were used in these horizontal wells. The design criteria, formulation, properties and applications of these fluids were discussed. For each mud system CaCO3 was used as a bridging agent. The particle sizes of CaCO3 were selected based on the average pore sizes of the target formations. It was observed that the three mud system had provided excellent formation protection with much less skin factors and much larger percentages of regained permeability as compared with other commonly used drilling and completion fluids. The oil production rates of most horizontal wells are three to five times higher than that of their adjacent vertical wells, which is highly related to the effective prevention of formation damage. Introduction It is well known that the major purpose of horizontal well drilling is to increase the contact area with reservoir exposed in the well and thereby enhance well productivity. In recent years, the horizontal well technology has been developed quickly in China, and more than fifty horizontal wells with various radii, most of which were located in Shengli field, were drilled in the 90's. It should be noted that the difficulty and cost of drilling and producing increase with the augmentation of well productivity. One of the major concerns is that the drilling-induced formation damage may be more pronounced for a horizontal well than that for a vertical well in the same formation from the point of view of the production loss (i.e economic loss) although it is generally considered that the horizontal well will likely be more tolerant of formation damage than the vertical well since the horizontal completion interval length is much longer. Thus, in order to give a full play to the economic benefit of horizontal well technology, it is necessary to know the characters of damage accounted during horizontal drilling and to develop techniques to minimize the extent of damage caused by drilling muds. The formulations, performance and effectiveness of these drilling muds were discussed. All this work was in connection with the horizontal wells drilled in Shengli and Dagang low-permeable sandstone formations. The test procedures to evaluate drilling-induced damage are similar to those provided in Ref. 2. Both the values of skin factor and regained permeability are mainly used as the measures of damage in this work. Flow tests through field cores were conducted at ambient temperatures. All the core samples were taken from vertical wells in the same formation and saturated with synthetic formation brines. These tests involved comparing the final (regained) permeability, after treated with drilling fluids, to the initial undamaged permeability. P. 739

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.

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.

Horizontal well drilling is a highly effective way to develop marine gas hydrate. During the drilling of horizontal wells in the marine gas hydrate layer, hydrate particles and cutting particles will migrate with the drilling fluid in the horizontal annulus. The gravity of cuttings is easy to deposit in the horizontal section, leading to the accumulation of cuttings. Then, a cuttings bed will be formed, which is not beneficial to bring up cuttings and results in the decrease of wellbore purification ability. Then the extended capability of the horizontal well will be restricted and the friction torque of the drilling tool will increase, which may cause blockage of the wellbore in severe cases. Therefore, this paper establishes geometric models of different hole enlargement ways: right-angle expansion, 45-degree angle expansion, and arc expanding. The critical velocity of carrying rock plates are obtained by EDEM and FLUENT coupling simulation in different hydrate abundance, different hydrate-cuttings particle sizes and different drilling fluid density. Then, the effects of hole enlargement way, particle size, hydrate abundance and drilling fluid density on rock carrying capacity are analyzed by utilizing an orthogonal test method. Simulation results show that: the critical flow velocity required for carrying cuttings increases with the increase of the particle size of the hydrate-cuttings particle when the hydrate abundance is constant. The critical flow velocity decreases with the increase of drilling fluid density, the critical flow velocity carrying cuttings decreases with the increase of hydrate abundance when the density of the drilling fluid is constant. Orthogonal test method was used to evaluate the influence of various factors on rock carrying capacity: hydrate-cuttings particle size > hole enlargement way > hydrate abundance > drilling fluid density. This study provides an early technical support for the construction parameter optimization and well safety control of horizontal well exploitation models in a marine natural gas hydrate reservoir.

Introduction Divinyl benzene co-polymer beads, better known as plastic beads, have been used for reducing torque and drag in conventional drilling operations for 17 years. Over the last four years, they have also been utilized to reduce friction in horizontal wells when drill pipe is not sliding at a fast enough rate, or is not moving at all. Co-polymer beads have also gained recognition as a means of reducing friction in coiled tubing workovers. Friction is reduced by introducing co-polymer beads between the drill string and bore hole. Laboratory testing and field experience have developed methods for reducing friction through specific application techniques. Application of the beads can vary, from spotting small "pills" in specific sections of the bore hole to carrying a concentration of beads throughout the system using a bead recovery unit. Drill string drag is the incremental force required to move pipe up or down in the hole, and torque is the force required to rotate pipe. The magnitudes of torque and drag are related in any particular well, and high drag forces and excessive torque loads normally occur together. There are a number of causes for excessive torque and drag. They include:tight hole conditions;sloughing hole;key seats;differential sticking;cuttings buildup because of poor hole cleaning; andsliding well bore friction. With the exception of sliding friction, these causes are associated with problem conditions in the well bore. Although all of these conditions can occur in horizontal wells, the primary source of torque and drag in a horizontal well with good hole conditions is sliding friction. The ability to alleviate sliding friction using co-polymer beads has proven to be extremely beneficial in horizontal drilling and workover operations, including standard pipe and coiled tubing. Sliding Friction Normal contact force and the coefficient of friction between contact surfaces are the two factors that affect sliding well bore friction. Another factor, capillary attraction, must be considered in open hole situations. Capillarity is described as the relative attraction of the molecules of a liquid where it is in contact with a solid. The relative attraction of molecules leads to a force of adhesion between a solid and a liquid. The wallcake of a well bore will exert very strong capillary attraction forces on a drill string when it comes in close contact with the drill string. This is explained by the fact that the wallcake or mudcake is composed of very small particles of clay, barite, sand, or other matter, and these minute particles will have considerably more surface area exposed for wetting by liquid than would larger particles in the same section of mudcake. The smaller the particles, the more surface area exposed for liquid wetting, thus the greater the attractive capillary force exerted. The capillary attractive force could lead to the drill string adhering to the wallcake, creating torque and drag. The beads, having a larger particle size than the solids in the wallcake, reduce this adhesive force.

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