Flow In a Constricted Horizontal Well

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).

"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 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.

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.

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.

Recently, there has been a heightened interest in the use of horizontal wells to more efficiently drain both oil and gas reservoirs and to compensate for negative producing situations such as coning. The potential applications of horizontal and high-angle wells have led to increased efforts to quantify the expected production increase from these types of completion methods in a variety of geologic settings. Simulation of these alternative completion methods using mathematical models provides a cost-effective method of predicting their performance and allows for sensitivity analysis of reservoir properties. The performance of horizontal and high-angle completions was simulated for marginal marine and lenticular low permeability gas reservoirs of the Upper Cretaceous Mesaverde Formation underlying the east-central Piceance Basin. Results of the simulations show that production from horizontal wells of intermediate length can be expected to be four times higher than that of vertical, stimulated wells draining large areas. The advantages of high-angle wells in lenticular sandstone environments remain unquantified, but a reasonable potential exists, especially when methane from deeply buried coals is considered.

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.

This work investigates the combined use of horizontal wells and hydraulic fracturing technology to improve steam utilization and process efficiency on steamflood operations. Enhancement of the production response obtained when combining both technologies was modeled using a fully implicit 3-D thermal reservoir simulator. The advantages of using hydraulic fracturing for thermal processes and especially for steam injection operations are explained by the "Heat Plane Source" concept presented here. Different scenarios for fractured horizontal wells were modeled: orthogonal, longitudinal, horizontal and multiple fractures. During conventional steam injection operations, heat convection and gravity effects become dominant in the near-wellbore region resulting in excessive heat losses and a heat chest of limited extent. Simulation results indicate that inclusion of hydraulic fractures will ensue better steam utilization and sweep efficiency improvement while minimizing convective oil override and reduction of operational costs. The cost effectiveness of the combined approach was evaluated using a decision analysis process and incorporating the production response into an economic model. Profitability was evaluated based on the Net Present Value response. Results suggest an accelerated and marked increase in cash flow, particularly during the early life of the project. The application of fracturing technology for steamflood operations will accelerate the response and overall performance from heavy crude reservoirs. The discussed approach is applicable to thinner reservoirs, dipping reservoirs, steam distillation drives and especially effective in layered reservoirs. Approach The main objective of this work is to investigate the performance of hydraulically fractured horizontal wells and their advantageous application for thermal recovery processes. Reservoir simulation was used to evaluate the combined use of horizontal wells and hydraulic fracturing as production techniques for improved steam management, effective field development, accelerate recovery, development of depleted zones, target bypassed oil banks, assisted gravity drainage scenarios and alternative completion/recompletion approaches. Analysis based on the productivity increase and ultimate cumulative recoveries indicate that the proposed approach may be an attractive production strategy for more efficient thermal recovery processes in heavy and intermediate oil reservoirs. Thermal Recovery Processes In-situ combustion, cyclic steam stimulation (Huff-n-Puff), continuous steam injection and hot water flooding are the basic thermal recovery processes. Thermal methods rely on several displacement mechanisms to recover oil. The relative importance of each mechanism depends on the type of oil being displaced and the related recovery process. Mechanisms such as; distillation drives and thermal expansion of the heated oil will add to recovery as crude distillation tends to reduce residual oil saturation. Lighter oil fractions vaporizes providing a miscible flood front in advance of the thermal front. However, thermal processes rely on crude viscosity reduction due to temperature increases as the most important recovery mechanism. P. 479

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.

Reservoir development is increasingly moving towards the heavy oil resources due to the rapid decline in conventional oil reserves. With the production of conventional low gravity crude oil being surpassed by heavy oil production in Alberta, the vast fields of heavy oil have been considered an emerging source of energy to the growing demands for oil and gas. Although the applications of thermal methods have been successful in many enhanced oil recovery (EOR) projects, they are usually uneconomic or impractical in deep and thin pay zones reservoirs. Therefore, polymer flooding is a preferred EOR technique in such reservoirs. An application of polymer flooding in heavy oil reservoirs dates back to more than half a century ago. However, it has long been considered a suitable method for reservoirs with viscosities up to 100 centipoises only. Recently, this EOR technique has attracted great attentions and become a promising method for oil recovery from heavy oil reservoirs with viscosities ranging from several hundreds to several thousands of centipoises. The main reasons for such a widespread application of the technique in heavy oil reservoirs during the last two decades have been rises in oil prices, extensive use of horizontal wells and advances in the polymer manufacturing technology. This paper aims to review the advances and technological trends of polymer flooding in heavy oil reservoirs since the 1960s. Upon the review, complete data sets of the laboratory works, pilot tests and field applications are established. The database provides qualitative description and quantitative statistics regarding both scientific research and practical applications. Then suitable ranges of some crucial affecting reservoir properties and polymer characteristics for successful field applications are examined. Finally, new screening criteria are developed specifically for heavy oil reservoirs based on an analysis of the data. The criteria are compared with the previously established ones. The outcome of this paper can be used as guidelines for screening, planning, design and eventually implementation of future projects.

As technology advances in horizontal well drilling, long horizontals completion are now preferred for producers aiming to explore more oil-bearing zones, especially in heavy or tight oil reservoirs. However, for strong waterdrive horizontal wells, abrupt increase of water-oil ratio and abounding unwanted water production severely affect the profitability of the field due to the constant decrease of oil production and premature well shutting. The targeted reservoir of this work is a typical heavy oil reservoir with strong waterdrive. By December 2014, the average water cut for the two productive layers has increased 40-70%, for some wells especially, the water cut has exceeded 95% causing frequent well shutin. Therefore, to ensure the productivity of the horizontal wells, water shutoff has become a challenging and urgent task. According to the aquifer identification and water influx diagnosis, 27 horizontal wells distributed in aforementioned two productive layers were first categorized into two groups in order of treatment difficulties, after which foam-assisted gel and gel treatments were designed and conducted. For the three of the treated wells, the average water cut was significantly reduced from 80.3% to 48.0%. Although the gross liquid production rates were slightly reduced after treatment from 31.7 to 27.7 t/d, the oil production rate was considerably increased by 28.1 t/d. By January 2016, 4 500 t of the incremental oil was produced indicating the success of the water shutoff jobs. However, it should be noticed that the water cut of the N2 foam-assisted gel treated well started to rapidly rise after two months. This is probably caused by inappropriate foam/gel volume ratio. The water control strategies and field results in this heavy reservoir will provide the necessary clues for the design and application of water shutoff treatments for horizontal wells driven by strong water.

Simulation and evaluation on enhanced oil recovery for steam huff and puff during the later phase in heavy oil Reservoir—A case study of block G in Liaohe oilfield, China

Using horizontal wells for primary production of heavy oil reservoirs is common in Canada but it is less frequent to employ them for waterflood. As a result, very few papers have been published on this topic. Similarly, numerous publications are available on the use of conventional forecasting methods to evaluate waterflood performances, but very few if any have focused on waterfloods with horizontal wells in heavy oil reservoirs. This is what this paper proposes to do. The production performances of over twenty horizontal wells from five Canadian heavy oil pools where waterflood has been implemented using horizontal wells have been studied. The pools are thin and bottom water is present in some of them; oil viscosity ranges from a few hundred to a few thousand centipoises. Conventional waterflood forecasting methods such as Arps, Yang and logarithm of Water-Oil Ratio (WOR) vs. Cumulative oil production were used and compared. However, the focus of the paper is not only the comparison of the various forecasting methods but also the evaluation of the performances of horizontal well waterfloods in these high oil viscosities. The Arps method appears difficult to use, especially when there are strong variations in injection rates. By comparison, the Yang and the WOR vs. Cumulative production methods appear more stable. The forecast in cumulative production can vary widely between these methods. Ultimate recovery is expected to vary from a few percent OOIP to over 20%OOIP. This paper will present the performances of several horizontal waterfloods in heavy oil reservoirs in Canada and compare several waterflood analysis methods. Very few if any paper has been published on this topic thus the information provided will be of interest to engineers who are considering using horizontal wells for waterflood as a follow-up to primary production in heavy oil reservoirs.

Heavy oil reservoirs are often characterized by high viscosity and poor mobility, which is more complex with the presence of bottom water. The conventional vertical well development method has low oil recovery efficiency and limited controlled reserves of a single well. In addition, water cut can increase dramatically when the edge-bottom water breaks through. Horizontal well and CO2 huff-n-puff is an effective alternative development model for heavy oil reservoirs. This development method makes efficient use of CO2 and accords with the “Carbon Capture, Utilization, and Storage (CCUS)”. The horizontal well can increase the drainage area. The dissolution of CO2 improves the mobility of crude oil and increases formation energy. In this paper, we established numerical simulation models based on the Liuguanzhuang oilfield in Dagang. The characteristics and producing rules of the horizontal well and CO2 huff-n-puff development in the heavy oil reservoir were studied. The results show that the production characteristics of horizontal well and CO2 huff-n-puff were similar to Steam-Assisted Gravity Drainage (SAGD). CO2 forms a viscosity reduction area above the horizontal well and the heavy oil flows into the wellbore due to gravity after viscosity reduction. The CO2 huff-n-puff can effectively enhance the production area of horizontal wells compared with the depletion development. However, the improvement in the production area gradually decreased as CO2 huff-n-puff cycles continued. There was a boundary of production area against the horizontal well, with the main production of heavy oil occurring at the upper and either end of the horizontal well. The CO2 huff-n-puff has a restraining effect on the edge-bottom water, which is confirmed via the proposed theoretical model.

Some heavy oils reservoirs present an unusual behavior when put on production under significant drawdown conditions. In these reservoirs, the high formation depressurization increments the recovery factor and accelerates the production rates driven by a solution gas mechanism. Due to the chemical and physical properties of these oils they tend to stabilize the dispersion of gas bubbles, promoting the generation of foam in the oleic phase. This foamy oil when compared with conventional oils result in a more productive response at similar drawdown conditions. The foamy oil phase behavior is the result of a number of complex mechanisms and requires a good understanding on each of them to estimate the potential response of these reservoirs. In this work, the role of key factors that affect the bubbly oil production is summarized.To outline the significance of key variables on the performance, a commercial optimization and uncertainty analysis software coupled with a mechanistic simulator is used. The simulator allows a detailed modeling of the physics involved on the generation and behavior of the foamy oils, in which the foamy oil is modeled as a disperse phase of gas bubbles in the oleic phase, including small mobile gas bubbles and larger trapped gas bubbles flowing as discontinuous gas dispersion which affect foam viscosity, compressibility, mobility and relative permeability. Fluid properties used in this work are from Maini (1996).The sensitivity and optimization analysis performed in this work on key reservoir variables and well operational parameters shows the significance of each factor on the production response. The relative importance of each variable is reported in tornado diagrams. Results showed that a strong approach on handling the reservoir unknowns are as crucial as the control of operational parameters from reservoir management point of view.Nowadays the foamy oil behavior and its favorable production response are not totally well understood. Solutions have been proposed but they are still controversial and the use of horizontal wells introduces more complexity in the production operations. In this work is provided an in-depth optimization and uncertainty analysis to outline the role of each major parameter affecting the production response and the recovery efficiency in this type of reservoirs using horizontal wells.