Horizontal Well Applications and Parameters for Economic Success

"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⁁

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.

This paper presents- an experimental investigation of the! effect of horizontal-vertical well configuration on oil recovery of Safanyia crude by alkaline flooding. Emphasis was focussed on the effect of horizontal well pattern on oil recovery. Also, the effects of three types of alkali solutions; sodium- carbonate; (Na2CO3) sodium ortha-silicate (Na4SiO4). and sodium hydroxide (NaOH) on cumulative oil recovery, in both secondary and tertiary processes using linear model, vertical- vertical two dimensional model, and horizontal-vertical schemes, were investigated. It was found that displacing Safanyia crude oil by NaOH solution having 1% concentration results in higher oil recovery in both linear and horizontal-vertical schemes. The highest oil recovery through horizontal-vertical schemes was obtained by, placing the horizontal well perpendicular to the line connecting the two vertical wells with a length that does not reach the boundary of the reservoir- Also, it was found that oil displacement efficiency in the tertiary process is higher than in the secondary process. Introduction The use of horizontal wells has been increasing very rapidly throughout the oil industry as advances in drilling techniques continue. In many reservoirs, horizontal wells can solve a number of oil production problems. However, in spite of a tremendous increase in literature references, little information is available on horizontal well applications in enhanced oil recovery (EOR) methods(1). Many published articles show that horizontal wells are still used primarily to solve specific production problems, These include low permeability formations especially fractured formations low permeability gas reservoirs, unusual gas sources, gas or water coning, thin formations, and viscous oil(2,3). Most horizontal well applications of EOR activities have been in the area of thermal recovery, primarily for steam stimulation and steam drive(4,5). Although there is relatively little published information on the use of horizontal injection wells, other than thermal recovery the for patterns of both horizontal injection and vertical production well, to increase the rate of flooding in EOR has been mentioned(6,9). Early laboratory work oncaustic flooding through horizontal wells (10) showed that the use of a horizontal wellas an injector in alkaline flooding increased oil recovery by a minimum of 8% o initial oil-in-place (IOIP) compared to vertical wells. This paper studies the effect of horizontal 0vertical well configurations in one uater of a five-spot pattern model on oil recovery by alkaline flooding. It also discusses the effect of alkaline type and concentration on oil recovery in secondary and tertiary processes. The study was not made ina scaled model. Instead, Safanyia crude oil from Saudi Aramco has been used to investigate qualitatively the effect of horizontal-vertical well configuration in one quarter a five-spot model. Experimental Work Fluid Properties The physical properties of the fluids used in this study are shown in Table 1. The crude oil is Safanyia crude received from Saudi Aramco. The oil has an acid number of 1.5 mg KOH/g crude oil. The oil acidity was measured according to IP 1/74 test analysis which is equivalent to ASTM D974 test (11).

Stable cones created by a horizontal well drilled with maximum clearance from the unwanted fluid are studied (Muskat9 type approach, using pertinent viscous flow potential), yielding practical values for the critical rate per unit length of a horizontal well, and for the critical cone elevation, depending on both vertical and horizontal permeabilities, oil thickness, both fluid gravities, and oil viscosity. Critical rate weakly decreases when vertical permeability decreases. The same type of analysis is repeated for a vertical well completed over a very short interval (modelized as a point source) also with maximum clearance from the gas cap or water table, yielding values of critical rate and cone height for the vertical well. In this case the critical rate slightly increases when vertical permeability decreases. The outcome of a comparison between both types of wells shows that a critical cone comes closer to the horizontal well than to the vertical well. Also horizontal wells generally allow higher critical rates than vertical wells, however this advantage lessens with increased anisotropy. Very simple formulas are provided to evaluate what gain in critical rate may be obtained from a horizontal well.

The purpose of this paper is to report on the field test results of the Texaco Canada Petroleum Inc. (TEXCAN) and the Alberta Department of Energy (ADOE, formally AOSTRA), Electrical Horizontal Well Project in the Lloydminster heavy oil area. Two vertical wells (15D-25-56-2W4 and 13C-30-56-1W4) and one horizontal well (16D-25-56-2W4) were connected electrically and heated. This paper presents an overview of electrically heating a horizontal well with vertical wells, the design of the electrical heating system, operational experience, test data, and a discussion on the successes and problems of the project. Three wells were electrically heated; two deviated vertical wells and one horizontal well. The pilot project experienced premature equipment failure and sand production problems. Although a significant production response was achieved at the vertical wells, ongoing operations were not achieved because of sanding problems. The sand problem required daily workovers on the wells to maintain operations. As a result of these problems, and the limited current that can be supplied from just two vertical wells, the thermal response at the horizontal well was 3 - 5 °C and no production response was observed. The project was a technical success in that electrical current from two vertical wells was returned to the power conditioning units via the horizontal well and a thermal response was observed at all the wells. At the vertical wells, there was at times a greater than three times productivity response during electrical heating operations. Introduction Horizontal Wells and Heavy Oil Horizontal wells, typically 500 m in length and longer, are common in the exploitation of heavy oil reservoirs around the world. Horizontal wells offer prospects of improved performance over vertical wells, primarily due to the larger contact area between the formation and the wellbore. Also, the technology for drilling a horizontal well is as advanced as for drilling a vertical well. The cost of drilling a horizontal well is about the same as the cost to drill two to three vertical wells. There are production disadvantages and problems that are unique to a horizontal well application in heavy oil reservoirs. The production rate declines very rapidly during the first several months of production. It is also possible that the entire length of the horizontal well may not be productive. In some production systems, the limiting factor in producing the oil is the mechanical limitation of the pumping equipment, which is exceeded because of the very high viscosity of the oil. Finally, there may be skin effects, such as the visco-skin(1) that may further reduce the productivity of the well. This skin effect and other thermally alterable skin effects (for example, asphaltene precipitation) can block flow into the well, thereby decreasing the effective length and productivity of the well. Increasing the effective length of the well and removing any skin effects can improve the productivity of the well. Electrical Heating Electrical heating of vertical wells has been attempted on several occasions with encouraging results(2-10). Until now, there have been no electrical heating tests that use horizontal wells.

This paper presents the results of a study that evaluated various recompletion and depletion scenarios for a cyclic-steam operation in the Midway-Sunset field. The field has vertical wells on one-quarter acre well spacing and most wells are completed through the entire 1000 ft thick pay. Currently, the upper half of the reservoir exists as a steam chest with remaining reserves occupying the lower portion of the reservoir. Possible production strategies are recompletion of existing vertical wells into the lower half of the existing oil column and drilling new horizontal infill wells. A model of an 80-well portion of the field was constructed and used to history match the field data. After history matching, a number of development strategies were simulated and compared. In this paper, we present:Current field status,Details of the model and input data,History match results,Simulation results of the vertical recompletion and horizontal infill wells,Comments on field results of a horizontal well drilled lower in the oil column in May 1996. Introduction Cyclic steam stimulation is a principal thermal oil recovery method in heavy oil reservoirs. In the process, steam is injected into the reservoir for several days to a few weeks and then allowed a soaking period to dissipate energy and form a heated zone in the vicinity of the wellbore. The length of the soaking period, usually 3 to 14 days, is chosen to maximize the heat transfer to the reservoir but to minimize heat losses to the cap and base rock. After soaking, hot oil and water are produced from the heated zone. The production period can vary from a few months to over a year. When oil production declines to a point where is no longer economical to produce, the whole cycle is repeated. Oil production response to the first cycle is usually higher than subsequent cycles. The decrease in oil viscosity with increasing temperature is the most important factor for improving the oil production rate by cyclic steaming. Increasing the reservoir temperature by steam injection reduces the oil viscosity and causes the heavy oil to behave more like a lighter oil. The net result is improved oil mobility (ko/uo). As temperature returns to its original state the oil reverts to its original viscosity if no distillation effects are present. The increase in reservoir temperature by cyclic steaming also causes the oil to expand and become less dense. The heated oil is then pushed into the well, driven by reservoir pressure or by gravity drainage, and is produced. For thick reservoirs with low pressure, gravity drainage is the dominant production mechanism. Gravity drainage is also responsible for exceptional cyclic responses in steeply dipping reservoirs containing low gravity crudes. The Midway-Sunset field is located in the southwest portion of the San Joaquin Basin in southern California (Fig. 1). It was discovered in the early 1890's, with the first commercial production reported in 1901. It is classified as a "super giant", with ultimate reserves of 2.75 billion barrels. The majority of the field's production and reserves comes from the Upper Miocene turbidite sand reservoirs. These sands were deposited in a series of interfingering submarine fans, and in some areas accumulated up to 1,500 feet in thickness. Due to the low gravity (14 API) and high viscosity (2,300 cp. at reservoir temperature of 95 F) oil, thermal recovery techniques such as cyclic steam, steam drive and in situ combustion have been successfully employed to produce oil from this field. The high efficiency of thermal recovery techniques has resulted in a recovery factor of 40% to date, while current field-wide production, at approximately 45,000 bopd is still significant. P. 349^

Husky operates seven mature vertical hydrocarbon miscible floods in the Rainbow Field. Up to June 1993, eleven horizontal wells have been drilled, one horizontal well re-entered for extension and one vertical well re-entered to drill a lateral. Even though these wells were all drilled into mature miscible floods, the variation of reservoir characteristics, the horizontal well location and exploitation strategy made each well unique in terms of drilling, completion, workover and production performance. This paper describes the evolution and improvements in horizontal well applications made in redeveloping these mature reservoirs. Advancements are described in several areas as follows: Drilling:the use of pilot holes;entering the reef laterally;overcoming damage, loss of circulation, and high torque and drag; andextending the existing horizontal hole. Completions and workovers:selective testing and stimulation of different zones along the horizontal hole using multiple open hole packers and sliding sleeves, or straddle packers on tubulars. Production strategy and reservoir optimization of EOR performance:controlled rate to approximtely twice vertical well rates;controlled vertical movement of the oil bank;interference tests with vertical wells;use of bottom hole chokes; anduse of circulation strings for combating asphaltene deposition. Introduction The potential applications of horizontal wells in miscible floods have been mentioned in previous papers(1–3). However, Husky's well 16-29-108-08W6M was the first field application(4). Later, other companies have also used horizontal wells in miscible floods(5). Husky has redeveloped six pools (Figure 1) since March 26, 1989, to improve the recovery of oil sandwiched between solvent and water zones in vertical hydrocarbon miscible floods, by drilling eleven new horizontal wells, one horizontal extension and one vertical well re-entry. The abbreviated well names on Table 1 will be used throughout the remainder of this paper. There have been significant differences in the drilling, completion and production techniques and problems encountered on these horizontal wells. Each well has outperformed its vertical offsets in the same pool in terms of oil production rates (Figure 2) and GOR (Figure 3), which is unique for such a large well program. The vertical well rates and GOR's are averages of all vertical wells producing the reservoir behaves as a typical pool with water drive. Because reservoir pressure has been largely maintained, the dominant depletion mechanism is water influx. Infill Vertical Wells Following development of the northern part of the pool on a 32 ha (80 acre) spacing pattern, about a dozen vertical wells were drilled on 16 ha (40 acre) spacing, either as infill wells or as pool edge (step-out) wells. In five wells which are truly infill wells, the initial (first-year) oil rate was lower than the initial oil rate for the four surrounding original vertical wells; except for the well in Lsd. 11-3-5-32WIM, the total daily fluid was also less than it was in the surrounding original vertical wells (Table 2).

Two laboratory 3D scaled models were developed to compare the performance of steam flooding in reservoirs having bottom water zone with the application of different well configurations. One of the models was triangular, designed to represent 1/12th of a 7-spot pattern and the other was a square that corresponds to ?th of a 5-spot pattern in the B. Kozluca field in Turkey. Nine experiments were conducted by using the triangular model with or without bottom water zone, whereas four experiments were conducted with the rectangular model. The well configurations were changed during the course of experiments to determine their effects on oil recovery. Bottom water thicknesses were changed to see the effects on oil recovery. The physical properties of crushed limestone and crude oil (12.4 ° API) mixture were kept constant during the experiments. Steam was injected through a vertical injection well in both models. Strings of thermocouples were used to observe 3D temperature distribution inside the models. The maximum oil recoveries were obtained by placing the horizontal producers along the hypotenuse of the triangular model and the diagonal of the rectangular model, respectively. Besides, in both cases, the same well configuration provided better oil recovery than any other well configurations even in the presence of a bottom water zone. Oil recoveries decreased with increase in the thickness of the bottom water zone. SOR increased in the presence of bottom water. Introduction The increasing demand of non-renewable fossil fuel energy and the gradual depletion of conventional crude oil reservoirs led to the development of heavy oil reservoirs. The most efficient means to recover oil from these heavy oil reservoirs is thermal recovery method in which heat is applied to the reservoir. The application of heat in the form of hot water, hot gases, and steam reduces the viscosity of these heavy oils upon which, a more economic recovery is readily obtainable. These days, the thermal recovery method is widely known and applied worldwide for secondary and tertiary recoveries. Of all the thermal recovery methods, steam injection is the most popular method. Following steam injection into any heavy oil reservoir, the viscosity, specific gravity and flow resistance of the fluid in the reservoir changes, resulting in oil production increases. The reduction in the viscosity as a result of an increase in the temperature, facilitates the movement of the heavy oil. Advantages of Horizontal Wells Because of their numerous advantages, horizontal wells have gained attention in the petroleum industry(1,2).Horizontal wells provide larger contact within a reservoir and hence, eliminate the need for multiple vertical wells to acquire same reservoir drainage. Recovery is two to five times greater than that of a non-stimulated vertical well.In the case of a reservoir where vertical penetration of the formations would be uneconomical, drilling of the horizontal well would render a sufficient well bore opening and a possibility of a more economic recovery.Horizontal wells in the reservoir where coning of water and gas are predominant provide a better oil recovery while minimizing the coning effects.

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.

Rubiales and Quifa are the Colombia's major heavy oilfields (oil gravity ranges from 11.3 to 14.4° API) with a current oil production of more than 260 MSTB with an oil viscosity ranges from 370 to 730 centipoises. Horizontal well technology is used to drill through unconsolidated sandstones with an active and strong aquifer, under primary depletion. Since 2006, 604 horizontal producer wells have been drilled and completed using slotted liner in open hole. The high water production rate from the beginning of the operation in the horizontal wells is the main problem to be controlled in the Rubiales and Quifa fields, due to the high cost of produced water treatment and other factors. Water production is inevitably associated with the oil production; however one of the biggest challenges is to delay the water production as much longer as possible. Rubiales and Quifa actually have a large number of closed wells that have reached its economic limits, mainly by high water production. This production imbalance is being addressed in the new horizontal wells, using inflow control devices (ICDs). The ICDs is placed in each screen joint to balance the production influx profile across the entire lateral length and compensate the permeability variation and therefore the productivity of each zone. In 2012, a pilot test has been designed and implemented in Rubiales field with three horizontal wells using passive ICDs completion. The performance of the ICD's is found to reach the highest cumulative oil production compared to neighboring wells. The main purpose of this paper is to detail the selection process design and results evaluation for the use of the passive ICDs in horizontal wells at Rubiales and Quifa Fields, heavy oil reservoirs.

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.

A recent study by the Wall Street Journal reveals that the hydrofractured horizontal wells in shales have been producing less than the industrial forecasts with the empirical hyperbolic decline curve analysis (DCA). As an alternative to DCA, we introduce a simple, fast and accurate method of estimating ultimate recovery in oil shales. We adopt a physics-based scaling approach to analyze oil rates and ultimate recovery from 14,888 active horizontal oil wells in the Bakken shale. To predict the Estimated Ultimate Recovery (EUR), we collapse production records from individual horizontal shale oil wells onto two segments of a master curve: (1) We find that cumulative oil production from 4845 wells is still growing linearly with the square root of time; and (2) 6401 wells are already in exponential decline after approximately seven years on production. In addition, 2363 wells have discontinuous production records, because of refracturing or changes in downhole flowing pressure, and are matched with a linear combination of scaling curves superposed in time. The remaining 1279 new wells with less than 12 months on production have too few production records to allow for robust matches. These wells are scaled with the slopes of other comparable wells in the square-root-of-time flow regime. In the end, we predict that total ultimate recovery from all existing horizontal wells in Bakken will be some 4.5 billion barrels of oil. We also find that wells completed in the Middle Bakken formation, in general, produce more oil than those completed in the Upper Three Forks formation. The newly completed longer wells with larger hydrofractures have higher initial production rates, but they decline faster and have EURs similar to the cheaper old wells. There is little correlation among EUR, lateral length, and the number and size of hydrofractures. Therefore, technology may not help much in boosting production of new wells completed in the poor immature areas along the edges of the Williston Basin. Operators and policymakers may use our findings to optimize the possible futures of the Bakken shale and other plays. More importantly, the petroleum industry may adopt our physics-based method as an alternative to the overly optimistic hyperbolic DCA that yields an ‘illusory picture’ of shale oil resources.

Horizontal wells have been used successfully in Canada to recover oil from marginal heavy oil reservoirs in Saskatchewan and Alberta. These reservoirs are often poorly consolidated; recovery operations in these reservoirs are, therefore, usually susceptible to sand production. A horizontal well could be partially blocked due to the deposition and accumulation of sand particles inside the wellbore. This study presents a mathematical treatment of the transport process of oil and sand particles inside a constricted horizontal well. The model described in this paper formulates the transport process mechanistically. Continuum assumption is made for the fluid phase (oil) as well as the solid phase (sand particles). Equations of mass and momentum conservation for the solid phase and the fluid phase are formulated. The oil is assumed to be Newtonian, and the sand particles are assumed to be spherical in shape and uniform in size. The model incorporates empirical correlations to describe the interaction between the two phases. The system of equations is solved numerically to determine the transient distribution of sand particles and oil, and their pressure and velocity distributions as a result of an expanding constriction inside the horizontal well. Numerical simulation results provided insight into the mechanisms involved in the transport process, thus enhancing the understanding of the flow of sand and oil inside a horizontal well. Introduction One of the most common applications of horizontal well technology in Canada is to recover oil from heavy oil reservoirs in Saskatchewan and Alberta. In heavy oil reservoirs underlain with bottom-water, the use of horizontal wells has been found to improve primary recovery performance prior to water coning, recovering up to 15% of the initial oil in place compared with only 5% for a vertical well(1). The recovery rate is also increased. Horizontal wells have also been successfully used for increasing steamflood recovery(2, 3). However, recovery operations in these heavy oil reservoirs are usually susceptible to sand production due to their unconsolidated nature. The produced sand could give rise to production problems, as the sand fill up the wellbore, prevent the operations of downhole pumps, etc.(4). In the case of horizontal wells, sand production potentially poses an even more serious problem, due to the settlement and accumulation of sand particles at different positions along the well, leading to the reduction of the cross-sectional area of the wellbore open to flow (Figure 1). The ultimate effect of sand deposition could be the partitioning of the horizontal well into several segments, leading to a loss of production and a negation of the principal advantage of horizontal wells (large contact area with the reservoir). The study reported here investigates this problem. Specifically the study examines, through numerical simulation, the transport and distribution of sand particles, and pressure, and velocity distributions in a horizontal well. A special feature of the model is the presence of a constriction inside the horizontal well.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167770, ’Design Optimization of Horizontal Wells With Multiple Hydraulic Fractures in the Bakken Shale,’ by Luigi Saputelli, SPE, Frontender Corporation; Carlos Lopez, SPE, BP; Alejandro Chacon, SPE, Halliburton; and Mohammed Soliman, SPE, Texas Tech University, prepared for the 2014 SPE/EAGE European Unconventional Resources Conference and Exhibition, Vienna, Austria, 25-27 February. The paper has not been peer reviewed. The ultimate performance of fractured wells in tight reservoirs is affected severely by the interfering effects inside the fracture and interfractures. The most important parameters for determining the optimum fracture length have been shown to be the formation permeability and the stimulated reservoir volume. Although studies have examined the performance of horizontal fractured wells and the fracture-geometry effect, fracture spacing and intersecting angles in vertical and horizontal wells should be investigated further. This study presents the results of a tight-oil-reservoir analogy. Introduction An efficient way to improve the productivity of ultratight shale formations is to increase the density of hydraulic fractures. Decreasing hydraulic-fracture spacing increases the productivity of the well, but the incremental production gain for each additional hydraulic fracture decreases. The current field practice is to develop 640- to 1,280-acre leases with 4,000- to 10,000-ft horizontal wells with multiple fractures. However, the determination of the optimal number of fractures is a challenge. Historically, many of the first horizontal wellbores were drilled using the openhole method in the pay zone. This allowed a significant portion of the wellbore to be in contact with the reservoir. In 2004, a coiled-tubing-deployed jetting assembly was successfully used to focus the stimulation treatments in the openhole wellbore. This further demonstrated that openhole horizontal wells can be successful. Another completion method of that period that is still used is the plug-and-perforation technique in cased holes. The disadvantage of using this completion method, however, is that fracturing fluids can come in contact with the formation for an extended period of time. Near the wellbore, the flow configuration in a transverse fracture intersecting a horizontal well can be of two types. Outside the fracture, the flow from the reservoir into the fracture is linear; inside the fracture, the flow is converging radial. Additionally, turbulence effects, fracture-conductivity impairment, scaling, and unstable wellbore flow regimes can play an important role in creating pressure drops, which affect well performance.

Agenda Introduction Horizontal well Intervention Geological Setting Tubing Conveyed Openhole Logging Isolation Candidate Selection 1996 Program Review Summary Recommendations Questions Figure. Williston Basin Setting (Available in full paper) Comments Weyburn Unit is located in the northern portion of the Williston Basin 125 km SE of Regina Figure. Weyburn Unit Sakskatchewan, Canada (Available in full paper) Comments 22 km long X 18 km wide = 396 square kms 130 horizontal wells with 253 legs 520 vertical producing wells 168 injection wells 1.2 billion barrels of oil in place Figure. Weyburn Unit - Production History and Forecast (Available in full paper) Comments field discovered in 1954 waterflood started in 1963 production peaked at about 7500 m3/d vertical infill program in 1980's horizontal pilots in 1991 and 1992 horizontal infill program started in 1993 and is still ongoing, the majority of which have been drilled under balanced opportunities identified until the end of 1998 the current production is 3500 m3/d horizontal wells account for 19% ofthe producing well count, however, they contribute 65% ofthe total oil production recently announced Canada's largest CO2 miscible flood at Weyburn, injection of CO2 by Q3 1999 Figure. Horizontal well Intervention (Available in full paper) Comments horizontal well technology, especially multi-lateral technology, has outpaced developments in cost effective intervention intervention can mean anything such as stimulations, isolations (mechanical or chemical), logging this project is another step in the development ofa horizontal well intervention strategy that will ensure that PanCanadian is aware ofor involved in development of the technology required to optimize recovery using horizontal wells the downhole environment in Weyburn is severe, H2S ∼5%, high brine and ofcourse will be faced with CO2 in the future all interventions must be compatible with the above 130 horizontal wells, 70% ofwhich are multi-lateral, with approximately 250 km of openhole section one small interval in a horizontal well that is in communication with the under lying Vuggy can be the dominant producing feature ofthe well quad wells have 4000 m ofopenhole section; where do we start looking? - only source ofinformation is fluids and pressure while drilling objective ofthis project was to isolate these highly conductive zones so that the well could be pumped down with the existing lift equipment for other projects this type of intervention could be used to reduce operating costs or to reduce voidage requirements when infrastructure constraints become apparent if intervention is impportant under waterflood it is critical under miscible flood