Adaptability Analysis and Evaluation of Different Water Control Measures Based on Physical Experiments

Maintaining efficient oil production from horizontal wells with varying reservoir properties is a significant challenge. In such scenarios, water breakthroughs can occur prematurely, hindering hydrocarbon recovery. Traditional completion techniques often lack the ability to effectively address this heterogeneity and achieve optimal water control. Autonomous Inflow Control Devices (AICDs) offer an innovative solution for mitigating water influx in horizontal wells. This downhole device automatically regulates fluid flow based on predefined parameters, enabling proactive water control and improved sweep efficiency. This paper presents a successful field case study utilizing RCP AICDs to control water production in a low-viscosity oil reservoir (1.47 cP) offshore China. The paper explores not only the optimal design workflow and value justification for AICDs but also the challenges that led operators to embrace this technology. This paper also emphasizes that to achieve the best results from the use of such technologies, it is essential not only to ensure optimal design but also to operate the wells under conditions that allow the AICD to perform at its highest efficiency. Notably, when AICDs were operated under optimum conditions in this study, the water cut exhibited a continuous declining trend since then, indicating sustained and greater water control effectiveness. This case study demonstrates the effectiveness of AICD technology in controlling water production as water cut reduction was observed at both the mid and later production stages in edge and bottom water reservoirs with low-viscosity crude oil. The well with AICD completion has managed, so far, to deliver 310% increase in cumulative oil production from the well compared to basecase/analogue wells while also extending the well life twice as much than expected. The well's actual cumulative oil production significantly surpassed pre-drilling predictions, reaching over 63,500 m3 and continuing. The implemented RCP AICDs played a crucial role in enhancing water control, improved reservoir management and oil production throughout the well's lifecycle. By effectively controlling water influx in a reservoir with exceptionally low oil viscosity, this pushes the boundaries of AICD applicability. This study offers valuable insights into how these devices can improve field development strategies by mitigating water production and reducing operating costs for lifting, processing and disposal of water plus greenhouse gas emission and energy consumption associated with the operations.

Horizontal wells are an effective well type for developing low oil column and strong bottom water reservoirs. In the early stages of development, they can effectively increase the drainage area and slow down the rate of water cut increase. However, in the later stage of development, there are problems such as unclear water outlet points in horizontal wells, difficulty in controlling water, and low oil recovery rate and recovery rate. Based on fine reservoir characterization and production dynamic data, this study accurately predicts the water flooding mode of horizontal well, and propose corresponding production measures to achieve stable oil and water control. Firstly, based on forward simulation and multi-attribute comparison, the minimum amplitude attribute is selected to predict the spatial distribution of reservoir. Secondly, four amplitude attributes that are highly correlated with interlayer thickness are optimized, and the weight coefficient is automatically obtained under interlayer thickness supervision, then the seismic attribute fusion is obtained to predict the spatial distribution of interlayer. Then, based on dynamic data, three modes of linear waterflood, point waterflood and multi-point waterflood are proposed. Linear waterflood is common in homogeneous reservoirs, and the production dynamic curve can be divided into three stages, namely, the long water-free oil production period, the slow rise in water content period and the high water cut period. And the quadratic derivative curve of water cut has no obvious jump point. For linear waterflood mode, increasing pressure can be used to maintain stable production with high fluid volume. Point and multi-point waterflood are common in areas with strong heterogeneity and intercalation, where remaining oil is enriched. The water breakthrough time and number can be determined by quadratic derivative curve of water cut.Then, the water breakthrough position is determined by combining the reservoir distribution, oil column height, interlayer distribution and numerical simulation. Finally, the intelligent subcompartment water control technology of horizontal wells is used for subsection water control to achieve water control and oil stability.This method has been successfully applied in L oilfield. L oilfield is a shallow water delta deposit, with oil column height of 20m, water body multiple of 60. The daily oil production of 22 wells is 1274 stb/day, and comprehensive water content is 97%. Based on the above study, the operation of stabilizing oil and controlling water in 5 horizontal wells was successfully implemented, resulting in an additional oil quantity of 1596 stb/day and water cut down to 80%, which successfully reversed the development situation of the oilfield.The successful stabilization of oil and controlling water in L oilfield shows that the above strategy is effective. This method provides a new approach for tapping potential of similar reservoirs.

Centrifugal pumps often suffer from performance degradation when conveying non-Newtonian fluids in the petrochemical industry, owing to the special rheological properties of the medium. Based on the entropy generation theory, this paper investigates the flow characteristics of centrifugal pumps conveying non-Newtonian fluids with different viscosities via rheological tests, numerical simulations, and experimental verification and analyzes the distribution of energy loss and its formation mechanisms. The results show that an increase in fluid viscosity leads to a rise in total entropy generation loss, a decrease in pump head and efficiency, and a shift in the dominant mechanism of entropy generation loss. Specifically, under high-viscosity conditions, wall entropy generation becomes the primary form of energy loss, accounting for 99%. As viscosity decreases, turbulent entropy generation emerges as the dominant energy loss mechanism, accounting for 69%, while the proportion of viscous entropy generation remains below 5%. Mechanism analysis reveals that under high-viscosity conditions, the shear-thinning property of non-Newtonian fluids increases the velocity gradient within the boundary layer, intensifying the shear effect on the wall and causing wall entropy generation to dominate energy loss. At low viscosities, the turbulent pulsation of the fluid is enhanced, and phenomena such as disturbances in the blade wake, flow separation on the blade suction surface, and recirculation in the impeller passage are exacerbated, promoting turbulent entropy generation to become the dominant factor. This study uncovers the unique energy dissipation law of non-Newtonian fluids in centrifugal pumps, providing a theoretical reference for the optimal design of chemical centrifugal pumps.

The theory of the automatic phase selection controller and its performance analysis

Horizontal wells are a proven and well acknowledged technology to enhance well productivity through an increase in reservoir contact compared to that of a vertical well under the same conditions. In the last three decades, a considerable effort has been directed to study flow around horizontal wells by many investigators. These studies have mainly focused on proposing practical tools (in the form of skin factor) for long-term well productivity estimation. The skin factor proposed can be applied in an equivalent (one dimensional radial) open-hole system replicating the flow around the actual complex three dimensional (3-D) flow geometry of the Horizontal well. However, all these studies concentrate on single-phase Darcy flow conditions. In gas condensate reservoirs, in addition to the three dimensional (3-D) nature of flow geometry, the flow behavior is further complicated by the phase change and the variation of relative permeability (kr) due to the coupling (increase in kr by an increase in velocity or decrease in IFT) and inertia (a decrease in kr by an increase in velocity) effects. Therefore, simulating such a complex 3-D flow using numerical commercial simulators requires a three dimensional fine grid compositional approach, which is very impractical, cumbersome and sometimes trigger convergence problems due to numerical instability. In fact, the introduction of a quick and reliable tool for long term productivity calculation is much needed in such systems. This work is aimed at the development of a practical, general, and easy-to-use method for defining an effective wellbore radius of an equivalent open-hole system, replicating flow around the 3-D Horizontal well in gas condensate reservoirs. Accordingly, a 3-D compositional finite element based in-house simulator was developed to accurately model gas and gas condensate flow around horizontal wells. A large data bank was generated, covering the impact of a wide range of pertinent geometric and flow parameters on the well performance. Then a general approach is proposed for estimation of an effective wellbore radius of an equivalent open-hole radial 1-D system replicating flow around the 3-D Horizontal well system. The effective wellbore radius varies with fluid properties, velocity, IFT, reservoir and wellbore conditions. The results of the proposed formulation, which benefits from suitable dimensionless numbers, has been tested against the simulator results not used in its development confirming the integrity of the approach. Also, the proposed formulation is applicable for both single-phase non-Darcy and two-phase gas condensate flow systems. With this approach, no numerical simulation is needed and instead a simple excel spread-sheet can predict the horizontal well performance, significantly facilitating engineering and management decisions relating to the application of horizontal well technologies.

"A 2,000- to 4,000-ft-long horizontal wellcan replace several vertical wells, reducinginvestment and operational costs." Introduction Horizontal-well technology is now beingused in EOR projects, especially in thermaloil recovery. Although horizontal wells haverecently been used in miscible and water-floodprojects, the main EOR applications to dateare in steam projects. Several horizontalwells have been drilled as pilot projectsfor thermal oil recovery in bitumen andheavy-oil reservoirs. A few field pilotsshow commercial viability. Thermal oil recovery is used to produceheavy oil or bitumen in high-permeabilityreservoirs. The main advantages of the useof horizontal wells are improved sweep efficiency, enhanced producible reserves, increased steam injectivity, and a decrease inthe number of wells required for fielddevelopment. This last point is especiallyimportant in thermal oil recovery projects, where several closely spaced vertical wellsare required for economic development. A2,000- to 4,000-ft-long horizontal well canreplace several vertical wells, reducinginvestment and operational costs. The maindisadvantage of horizontal wells is theirinitial cost. Moreover, horizontal wells arecommonly completed in only one zone ata time, resulting in drainage of only onelayer. Horizontal wells have been completedin multiple zones, although not yet in thermaloil recovery applications. In bitumen reservoirs, attaining reasonableproduction rates without steaming is difficultbecause of the high oil viscosity. (Bitumenis oil with less than 10API gravity anda viscosity of more than 10,000 cp atreservoir conditions.) Steam injectivityalso can be a problem. Even with horizontalwells, initial steam cycling normally will benecessary to establish steam injectivity. Incontrast, in heavy-oil reservoirs, wells canbe produced at low rates even without steaminjection. (Heavy oil has a gravity of morethan 10API and a viscosity of less than10,000 cp at reservoir conditions.) Here, steam injection with horizontal wells isprimarily to enhance production rates, toimprove sweep efficiency, and to increaseultimate oil recovery. Injectors or Producers Horizontal wells can be used as injectors orproducers. The large contact area ofhorizontal wells can enhance injection ratesin injection wells and improve productionrates in producing wells. When horizontal wells are used as producers, they providea large producing capacity with highproduction rates. Hence, high steam injectionrates in surrounding injection wells arenecessary to maintain reservoir pressure. Whenhorizontal wells are used as injectors, theninjecting steam uniformly along the well length occasionally may be difficult, espeially during the initial steam-injection period. This is because steam condensation ina cold horizontal well reduces the welllength available for steam injection. Thisproblem can be reduced or eliminated bypreheating a long horizontal wellbore beforesteam injection. In field applications, excluding cyclicsteam stimulation, horizontal wells are usedmore often as producers than as injectors. In horizontal producers, at least initiallybefore the heat front arrives and the entire wellbore is heated, only cold heavy oil maybe produced. The pressure drop in the longwellbore can be significant because of thehigh viscosity of the cold oil, which maycause uneven production along the welllength. Recovery Process Concepts Horizontal wells provide flexibility indeveloping well patterns for enhancing theweep efficiency of thermal oil recovery. Itpossible to drill a long horizontal well, or to re-enter an existing vertical well and drill short drainholes 100 to 300 ft long)to enhance steam injectivity and/or oilproductivity. This procedure can beespeially useful in multilayered reservoirswhere a specific zone can be developed witha minimum number of vertical wells. In multilayered heavy-oil reservoirs, suchis those in South America, production insome zones is delayed because of theunavailability of producing wells. In thesemultilayered reservoirs, the number of wells required to drain several zonessimultaneously is too large. JPT P. 1302⁁

The field-A1 is an offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. The permeability distribution varies across different layers with an overall permeability of 680 m and porosity distribution for the reservoir field-A1 varies 0.21-023. The reservoir thickness also varies up to 50 m thick. This research work identifies parameters that will contribute to the impact of water coning. Simulation sensitivities are run to observe the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. Results have shown that put horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer due to less recovery compared to north-south and original wells orientation (northwest-southeast). The varying height of perforation and standoff as identified is at the standoff between 30-40 m in the field-A2 will delay water coning high recovery with more extended plateau length period. The gas recovery may happen to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index that is the performance of the well. Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery the high drawdown tendency is observed before water breakthrough time however there is early water breakthrough, thus use of deep penetration. Horizontal gas wells have a constant horizontal length for all cases of 300 m increasing tubing head pressure from 40-100 bars result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning. The gas recovery is reduced by 5%. Gas recovery is increased with an increase in gas rates constrain, and early water breakthrough is observed when producing at high rates. Producing at low rates may delay water coning. However, it is not economical since there is less gas recovery and may take a more extended period for production to reach to its total maximum gas production of which is less compared when producing at high gas rates. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. This aquifer impacts the gas recovery reduction by 19%, with water coning radial extension of 1.7 km and peak water production rate for 16 years. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. Therefore, from the results producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Also, it is essential not to perforate if well is near to gas water contact the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning.

Numerical simulation of proppant transport from a horizontal well into a perforation using computational fluid dynamics

A compositional equation-of-state simulator has been used to make comparisons of CO2 process performance with several combinations of horizontal and vertical wells and various alternative reservoir descriptions. This is the first time that the performance of CO2 flooding using horizontal wells has been reported. We have used the reservoir and fluid properties of an actual West Texas carbonate reservoir that is currently being waterflooded. The phase behavior and properties of the CO2 used in these simulations are typical of those of multiple-contact- miscible field conditions of West Texas. A layered-type reservoir description was initially used to investigate the effect of water- altemating-gas (WAG) ratio with various combinations of well types. We then investigated the effect of vertical permeability, length, and position of the horizontal injector using the same reservoir description and a horizontal injector-vertical producer combination. Similar investigations using an unconditioned stochastic permeability field having a Dykstra Parsons coefficient (VDP) of 0.81 were made. Our final three-phase flow simulation was performed using a stochastic permeability field conditioned with core data. Since three nonaqueous phases can occur at low temperatures typical of West Texas floods resulting in up to four-phase flow with mobile water, we investigated the impact of four-phase flow in one of these simulations. This is the first time that three-dimensional, four-phase flow reservoir simulations have been reported with either vertical or horizontal wells.

A number of heavy oil and oil sand reservoirs in Alberta have been successfully produced by natural depletion at rates far in excess of the predictions based on radial Darcy flow. Production rates can exceed 20 m3/d and con be maintained at such a high level for several years. What exactly causes the high primary production rates is not known, but several mechanisms on the primary production of heavy oil and bitumen have been proposed by various authors. These include solution gas drive, influx of bottomwater, sand production, wormholes, fractures and channels. Laboratory measurements which have been reported on the rheological properties of bitumen indicate that at low temperatures (e.g. 20 °Cj a mixture of bitumen or heavy oil with a small amount of sand behaves as a non-Newtonian fluid. The flow characteristics of a non Newtonian fluid in a reservoir and their effects on the primary production of heavy oil have been investigated in this study using ana/ysica/ solutions of the diffusivity equation. It was found that di/atant (shear thickening) effects can provide an explanation for low apparent viscosities at a distance from the wellbore where shear rates are low. This mechanism is consistent with the pressure buildup test results and with field production data where high production rates can be sustained over an extended period of time. Introduction A number of heavy oil and oil sand reservoirs in Alberta and Saskatchewan have been successfully produced by natural depletion. Primary recovery at the Lloydminster heavy oil deposit, which began over 40 years ago, has been significantly higher than the predictions based on radical Darcy flow. The heavy oil deposits in this area are relatively thin (3 m to 6 m) and occurring at depths from 300 m to 1000 m. The formations consist of unconsolidated sands with a relatively high porosity (29% to 35%) and high permeability (3500 mD). The oil gravity is quite low ranging from 10 to 20 degrees API with an oil viscosity of 400 mPa.s to 2000 mPa.s at initial reservoir conditions. Since 1985, Amoco have been producing significant amounts of bitumen from the Lindbergh Elk Point(1) area on primary production. The Clearwater formation at this location is 25 m to 30 m thick and consists of a moderately well sorted sand. The bitumen has a gravity of about 12 degrees API and a very high viscosity of 60 000 mPa.s at reservoir conditions (3900 kPa and 2O °C). The primary production rates average 15 m3/day 00 20 m3/day for over 3 years. These production rates are greater than can be predicted with radial Darcy flow calculations by a factor of more than 30. Potential Mechanisms It is not known what exactly causes these high primary production rates but a number of potential mechanisms have been suggested. in the literature: solution gas drive; influx of bottomwater; sand production; wormholes, fractures and channels; and rock compressibility. Smith(2) suggested that a possible production mechanism could be solution gas drive which was assisted occasionally by the influx of water.

Autonomous Inflow Control Devices (AICD) have been commercially available since 2010 and there are many published case studies of wells in sandstone reservoirs, encompassing a wide variety of water and gas control scenarios. There are, however, relatively few documented studies of AICD for water control in fractured carbonate reservoirs. This paper will discuss and compare two trial wells that were completed with AICD in Eastern Montana in late 2022. Mission Canyon is a limestone formation of the Mississippian age and is associated with the Williston Basin of the North Central United States. It is composed primarily of oolitic calcarenite consisting of sedimentary carbonate grains. Depending on the grain size, matrix permeability can be relatively low, and a complex network of natural fractures is what dominates fluid flow. These fractures can be good or bad; they can deliver a good oil rate, or they can be direct conduit to the reservoir’s natural bottom-water drive. Consequently, most wells start with 50% water cut and reach 90%+ within a few months. Water volumes can be as high a 3000 barrels of water per day, per well, requiring large-volume pumps and significant water handling & disposal infrastructure. This field trial of AICD technology was designed to reduce water production rates, and then evaluate the impact on additional oil recovery. The technology tested was an AICV (autonomous inflow control valve) that utilizes the fluid viscosity and density to autonomously restrict water. The AICV devices were installed in two wells; the first was an existing horizontal producer (retrofit installation) and the second was a newly drilled horizontal well. AICV were installed on 3-1/2" liners in the open-hole horizontal section, compartmentalized into stages by swellable packers. Each compartment of the well was approximately 150 ft long and was controlled by a dual AICV flow screen. Nodal analysis predicted a 50% reduction in produced water, with an increase of 20-30% oil rate versus the standard open-hole laterals. This field study documents the world’s first application of the AICV technology for light oil, water control in a fractured carbonate reservoir. Many valuable lessons were learned on how to best complete and operate the wells. Preliminary results show effective water control, regardless of pressure drawdown. The paper will share production results for each well and attempt to estimate the net effect on oil production and well economics.

One of the largest clastic reservoir fields in the Sultanate of Oman has been discovered in 1980 and put on production in 1985. The field produces viscous oil, ranging from 200 - 2000+ cP at reservoir conditions. Over 75% of the wells drilled are horizontal wells and the field is one of the largest producers in the Sultanate of Oman. The field challenges include strong aquifer, high permeability zones/faults. Due to large fluid mobility contrast, the fields have experienced in pre-mature water breakthrough that has resulted in very high-water cuts. The average field water cut for open hole horizontal well after 6-9 months of production is over 94%. This paper details a meticulous journey in qualification, field trials followed by field-wide implementation and performance evaluation of Autonomous Inflow Control Valve (AICV) technology in reducing water production and increasing oil production significantly. AICV can precisely identify the fluid flowing through it and shutting-off the high water or gas saturated zones while producing oil from healthy oil-saturated zones. Like other AICDs (Autonomous Inflow Control Device) AICV can differentiate the fluid flowing through it via fluid properties such as viscosity and density at reservoir conditions. However, AICV's performance is superior due to its advanced design based on both Hagen-Poiseuille and Bernoulli's principles. This paper describes a comprehensive AICV completion design workflow that was developed across a multi-disciplinary team. Some of the initial wells completed with AICV has shown the benefit of accelerating oil production of over 30,000 bbls within the first few months of installation. Many wells started with 5-10 % water cut and are still producing with low water cut and higher oil production. The operator has approved AICV technology based on techno-commercial analysis and its positive impact on the project such as accelerated oil production and lower cost of water handling at the surface. AICV also helped in mitigating the facility constraints of handling produced water which resulted in reduce OPEX as allow the operator continued to drill horizontal wells. At the time of writing this paper, the operator has completed several dozen wells in the field with AICV technology and has an aggressive long term plan to complete several new and old wells. Finally, this paper also discusses in detail the comparative analysis of AICV wells for different subsurface conditions and share some lessons learned to further optimise the well performance. The technology has a profound impact on improved sweep efficiency and as well plays an instrumental role in reducing the carbon footprint by reducing the significant water production at the surface. It is concluded that AICV is a cost-effective field-proven technology for the water shut-off application. Due to its ability to autonomously identify and shut off water and gas production, the AICV technology has been approved to use as full fields implementation and in other fields. Field Background and Reservoir/Production challenges The operator produces around nine barrels of water against each produced barrel of oil. In general, the water produces to the surface with hydrocarbons contains many chemicals, which are usually not environmentally friendly and required additional treatment which increases the disposal cost. The Operator was looking for a cost-effective and proven technology that can control/shut off water production and improve oil production. The fields have a strong bottom aquifer and heterogeneous reservoir properties, such as permeability and downhole water saturation profiles. The challenge with matured brownfields, typically newly drilled wells will have pre-mature water breakthrough within few months of production. The fields have a highly viscous oil, with viscosity ranges from 200 cP up to 2000 cp at downhole conditions, thus creating a high mobility contrast between the oil and water, causing water fingering and coning at an early stage of production. These production challenges cause a significant recoverable oil left in the reservoir i.e. bypassed oil. Furthermore, excessive surface water production affects the integrated production system back pressures and flow, as well as an individual well's dynamics and pump efficiencies. This also has a significant downstream impact, where substantial investment is needed to handle, treat, and dispose of the water. Reducing these water volumes at the surface adds up to a tangible reduction in OPEX for water processing as well as environmentally friendly and assist the reservoir to maintain the reservoir pressure and energy by keeping the water in the reservoir. (Hilal et al 1997, Hassasi et al 2020)

One of the common applications of horizontal wells is the development of thin oil columns underlain by bottom water and/or overlain by a gas cap. Vertical wells are not suited in this situation due to the rapid coning of water or gas at reasonable production rates. Horizontal wells correctly positioned in the oil column, however, can produce at high flow rates with very little drawdown. The small drawdown significantly delays the breakthrough of water or gas at flow rates much higher than the flow rates possible from a vertical well. The flow distribution in a horizontal well designed to develop a thin oil column can be significantly impacted by friction losses in the wellbore. The impact of friction results in a higher drawdown at the heel as compared to the toe of the horizontal well. While this impact is insignificant in lower permeability systems, it can lead to premature water or gas breakthrough at the heel of the well in high permeability systems produced with low reservoir drawdown. Skin damage is normally undesirable due to its detrimental impact on well productivity. In high permeability systems developed with horizontal wells, however, well productivity is normally not a problem. Skin damage actually diminishes the detrimental impact of friction in horizontal wells by improving the flow distribution. This study investigates the intentional inclusion of mechanical skin damage in a high permeability, North Sea horizontal development. Reservoir simulation was used to justify and design a limited entry completion that was shown to improve flow distribution and oil recovery, at a significantly lower completion cost. The desired uniform flow rate distribution was confirmed by a PLT run in the first well, and through reservoir simulation and history matching.

Horizontal and drainhole drilling have been used successfully to increase productivity of wells in the past years. Many formulae can be used to compute the productivity of horizontal or slanted wells compared to vertical ones. One objective of this work is to recall the proper way to use these formulae and to recall the assumptions made that may limit their use. The increase of productivity due to longer perforated interval increases as the logarithm of length and can reach values of two or three times the vertical well. Also presented is a sample calculation of the influence of natural or artificial fractures on well productivity: a horizontal well may take advantage from an existing fracture network, much better than a vertical well would have. This is because the most permeable fractures are the open ones which have their planes parallel to the largest stress, and the largest stress is generally vertical because of rock weight. The productivity of a drainhole in a fractured medium can raise to 10 times the productivity of the drainhole alone. Another improvement expected from horizontal wells is a larger flexibility regarding coning problems: it is possible to produce with an interface while keeping a good productivity and a high critical rate. The analytical means for critical rate computation are reviewed with their assumptions. Model computations give the examples of supercritical production in the bottom water drive case. The advantage of horizontal well is important at water breakthrough but does not increase much after and even decreases for favorable mobility ratios. Short drainholes may perform as well as horizontal wells if their distance allows a large interference of cones. The third way of using horizontal wells is to increase areal sweep efficiency in regular pattern floods. The pattern showing the poorest efficiency is the direct line drive. Using horizontal wells drilled along the lines of producers can bring the areal sweep efficiency close to perfection. In that particular use, horizontal wells act like artificial fractures, with the advantage that their orientation can be controlled.

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.