Slanted Wells Research Articles

Characteristics of unsteady flow to wells in unconfined and semi-confined aquifers

An approximate solution by Zhan and Zlotnik for flow to a horizontal or slanted well in an unconfined aquifer is shown to be general enough to include the earlier solutions of Theis, Hantush and Jacob, Boulton and Neuman and is used to investigate the behavior of flow to a well in unconfined and semi-confined aquifers. The semi-confined aquifer is bounded on top by one or more aquitard layers containing a free surface, which is allowed to draw down with time as flow is abstracted from the well. Drawdown curves for unconfined and semi-confined aquifers are observed to have similar shapes but greatly different time scales, drawdown magnitudes and drawdown distributions along vertical lines in the pumped aquifer. This emphasizes the importance in applications of choosing mathematical models that correctly fit aquifer geologies. The Zhan and Zlotnik solution utilizes several approximations, and comparing solutions for flow to vertical wells in unconfined and semi-confined aquifers with the exact Neuman and Boulton solutions tests the accuracy of these approximations. Then the solution is used to plot drawdown contours around a horizontal well in an unconfined aquifer, and a number of reasons are given for the relative efficiency of using a horizontal well to abstract water from an aquifer.

Flow to horizontal drains in isotropic unconfined aquifers

The Laplace-transform solution for the problem of flow to horizontal drains in an anisotropic unconfined aquifer is derived. The solution for the constant flux horizontal-well by Zhan and Zlotnik [Zhan, H., Zlotnik, V.A., 2002. Groundwater flow to a horizontal and slanted well in an unconfined aquifer. Water Resour. Res. 38(7), 13-1–13-11.] is modified to obtain the solution for a constant head horizontal drain. The Laplace-transform solution is converted to the real time domain, and type curves for the drawdown around and the discharge to a horizontal drain are computed. The solution is verified by a numerical simulation. The type curves and derivative type curves of the drains are compared with type curves for horizontal wells. The sensitivity of type curves on piezometer location, specific storage, horizontal drain elevation, aquifer delay index and drain length is tested. These type curves can be used for interpretation of drainage data.

Groundwater flow to a horizontal or slanted well in an unconfined aquifer

New semianalytical solutions for evaluation of the drawdown near horizontal and slanted wells with finite length screens in unconfined aquifers are presented. These fully three‐dimensional solutions consider instantaneous drainage or delayed yield and aquifer anisotropy. As a basis, solution for the drawdown created by a point source in a uniform anisotropic unconfined aquifer is derived in Laplace domain. Using superposition, the point source solution is extended to the cases of the horizontal and slanted wells. The previous solutions for vertical wells can be described as a special case of the new solutions. Numerical Laplace inversion allows effective evaluation of the drawdown in real time. Examples illustrate the effects of well geometry and the aquifer parameters on drawdown. Results can be used to generate type curves from observations in piezometers and partially or fully penetrating observation wells. The proposed solutions and software are useful for the parameter identification, design of remediation systems, drainage, and mine dewatering.

Proposed Air Injection Recovery of Cold-Produced Heavy Oil Reservoirs

Abstract This concept paper explores the potential applications of air injection (in situ combustion) as a follow-up to cold production of heavy oils. Cold-produced fields are ideal potential candidates for air injection due to the significant resource that remains at the economic limit of cold production, and because wormhole- type channels are present in the depleted reservoir. The authors propose steaming the depleted reservoir for a short period of time to collapse the wormholes, thus creating high permeability heated channels. Reservoir ignition and air injection would follow, with the heated channels providing a flow path for the mobilized oil to reach the production wells. The steam/combustion combination would be highly effective in thin reservoirs, where extended steam injection is uneconomic. Additionally, this process addresses the three technical causes for failure in heavy combustion projects: ineffective ignition, inadequate air injection rates, and temporary plugging of the formation due to blockages caused by high liquid saturations. An overview of cold heavy oil production and heavy oil by in situ combustion is provided, as well as a detailed discussion of the proposed process. Introduction Cold Production in Western Canadian Heavy Oil Regional Sands Western Canada contains extensive heavy oil and bitumen deposits, as is shown in Figure 1. Early primary production of this resource using reciprocating pumps in vertical, directional, or slant wells was only economic in the Lloydminster Block; thus, most of the existing geologic studies are for this area(1–3). Following the development of progressing cavity (PC) pumping technology in the 1980s, cold production from these wells (vertical, directional or slant) was expanded rapidly to several additional areas, including Frog Lake, Elk Point, Lindbergh, and portions of Cold Lake and the Primrose Block. This exploitation methodology provides a large percentage of the produced oil volume for most Western Canadian heavy oil producers; in fact, some producers use only this method. Most cold production of heavy oil has been conducted in regional sands from the Lower Cretaceous Mannville Group (see Figure 2). Stratigraphic nomenclature varies locally, but, in general, most Lloydminster area regional sand cold production is from the Sparky and Waseca sands, while most of the Frog Lake, Elk Point, and Lindbergh cold production is from the Cummings.Regardless of the nomenclature, from a reservoir engineering perspective, these sands are characterized as being relatively thin, clean, with high porosity and permeability, and containing high saturations of heavy oil(4). Figure 3 is a plot of the estimated distribution of oil in place vs. sand thickness for the Lloydminster area, and Table 1 describes regional sand properties. Bottom water and edge water are common features, and a significant fraction of the wells in this region become uneconomic due to rapid water influx. Despite continued efforts to improve PC pump-based cold production technology, current methods generally leave 80 to 95% of the OOIP behind at the economic limit. This is a large oil-in-place target for follow up EOR processes; however, the cold production process appears to have strongly altered reservoir conditions from their original state.

Characterization and optimization of slanted well designs for microfluidic mixing under electroosmotic flow

Recently, a series of slanted wells on the floor of a microfluidic channel were experimentally shown to successfully induce off-axis transport and mixing of two confluent streams when operating under electroosmotic (EO) flow. This paper will further explore, through numerical simulations, the parameters that affect off-axis transport under EO flow with an emphasis on optimizing the mixing rate of (a). two confluent streams in steady-state or (b). the transient scenario of two confluent plugs of material, which simulates mixing after an injection. For the steady-state scenario, the degree of mixing was determined to increase by changing any of the following parameters: (1). increasing the well depth, (2). decreasing the well angle relative to the axis of the channel, and (3). increasing the EO mobility of the well walls relative to the mobility of the main channel. Also, it will be shown that folding of the fluid can occur when the well angle is sufficiently reduced and/or when the EO mobility of the wells is increased relative to the channel. The optimum configuration for the transient problem of mixing two confluent plugs includes shallow wells to minimize the well residence time, and an increased EO mobility of the well walls relative to the main channel as well as small well angles to maximize off-axis transport. The final design reported here for the transient study reduces the standard deviation of the concentration across the channel by 72% while only increasing the axial dispersion of the injected plug by 8.6 % when compared to a plug injected into a channel with no wells present. These results indicate that a series of slanted wells on the wall of a microchannel provides a means for controlling and achieving a high degree of off-axis transport and mixing in a passive manner for micro total analysis system (microTAS) devices that are driven by electroosmosis.

Rapid microfluidic mixing.

A preformed T-microchannel imprinted in polycarbonate was postmodified with a pulsed UV excimer laser (KrF, 248 nm) to create a series of slanted wells at the junction. The presence of the wells leads to a high degree of lateral transport within the channel and rapid mixing of two confluent streams undergoing electroosmotic flow. Several mixer designs were fabricated and investigated. All designs were relatively successful at low flow rates (0.06 cm/s, > or = 75% mixing), but had varying degrees of success at high flow rates (0.81 cm/s, 45-80% mixing). For example, one design operating at high flow rates was able to split an incoming fluorescent stream into two streams of varying concentrations depending on the number of slanted wells present. The final mixer design was able to overcome stream splitting at high flow rates, and it was shown that the two incoming streams were 80% mixed within 443 microm of the T-junction for a flow rate of 0.81 cm/s. Without the presence of the mixer and at the same high flow rate, a channel length of 2.3 cm would be required to achieve the same extent of mixing when relying upon molecular diffusion entirely, while 6.9 cm would be required for 99% mixing.

Estimation of reservoir properties using transient pressure data: An asymptotic approach

An asymptotic formulation of the inverse problem for flow reveals that the inversion may be partitioned into two complementary subproblems. In the first problem the arrival time associated with the peak slope of the transient curve is directly related to reservoir properties. The second inverse problem is similar to current methods for interpreting flow data; the transient head amplitudes are related to reservoir storage and conductivity. The first subproblem, the arrival time inversion, involves much less computation than does amplitude matching. Furthermore, it appears to be more robust with respect to the starting model. Therefore the solution to the arrival time inversion provides a starting model for amplitude matching. The methodology is particularly suited to the analysis of observations from well tests. We apply the approach to observations from two interference tests conducted at the Borehole Test Facility in Oklahoma. Using the transient pressure measurements, we image a shallow conductive fracture. The existence and location of the fracture has been verified by both geophysical and borehole data. In particular, core from a slant well contains an open, vertical fracture which coincides with our conductive feature.

Reduction of Surface Casing Vent Leaks In Viking/Kinsella, Alberta Using Improved Drilling And Cementing Techniques

Abstract Surface casing vent leaks (SCVLs), subsequent to production casing cementation, became a serious concern in the Viking/Kinsella area. The gas sand formations responsible for the SCVLs were relatively shallow, low temperature, and overpressured. Drilling angled wells from pad locations increased the possibilities of SCVLs due to the difficulty in obtaining a good primary cement job. Conventional drilling and cementing practices did not prove effective in reliably preventing environmental liabilities were incurred. PanCanadian Petroleum Ltd. Has implemented a number of drilling and cementing "good practices" to reduce SCVL incidents. The changes in drilling and cementing practices and materials have resulted in a significant reduction in the number and severity of SCVLs. Introduction The main objective of a successful primary cementing operation is the complete displacement of drilling fluids and solids from the drilled hole/casing annulus with a competent cement slurry designed for area specific concerns. Industry research and experience has shown that even a properly designed cement slurry cannot provide an effective hydraulic seal if contaminated with drilling fluids or solids, or if a channel through the cement exists. Drilling practices have an impact on the quality of the wellbore to be cemented, as well. This paper addresses the changes in drilling practices and cement design established to eliminate surface casing vent leaks (SCVLs) at the PanCanadian Viking/Kinsella development project. Background The Viking/Kinsella field is located 20 km northeast of Viking, Alberta, in TWP 47 RGE 9 W4M. PanCanadian's wells in this field historically suffer from poor zonal isolation and high frequency of SCVLs. A SCVL is defined as any measurable flow or pressure build up of gas, water or hydrocarbon liquid on a vent on the surface casing bowl(1). This paper specifically refers to SCVLs from gas sources. The source formations (Figure 1). PanCanadian set a goal to eliminate all SCVLs in an effort to reduce well lifecycle cost in the area. PanCanadian utilizes slant well pad drilling in the Viking/Kinsella area to reduce:Capital costs when compared to directional drillingOperating costs; maintain fewer leases and facilitiesWell production operating costsEnvironmental impact by minimizing surface land requirements A typical well configuration consists of: Equations (available in full paper) The operational issues that were addressed in the drilling and cementing of the slant wells in the Viking/Kinsella are:Complete removal of drilled solids from hole,Optimal casing centralization, andOptimal slurry design Mechanical Considerations Numerous cementing techniques have been considered throughout the industry to combat SVCLs, all with limited success. They include:Applying additional pump pressure from surface to compensate for hydrostatic losses due to slurry gelation,Placing a fast setting cement at surface and "pancake" squeezing a slower setting slurry into the gas zone, orInflating an external casing packer at the surface casing shoe to provide a mechanical barrier to gas flow.

Acoustic signatures of a fracture during air injection

This study examines the acoustic signatures of transmitted, reflected, and guided waves during air injection into a single, natural, water-saturated fracture in limestone. The presence and location of the fracture were established in a series of geologic, hydrologic, and seismic studies (Queen and Rizer, 1990; Datta-Gupta et al., 1994; Majer et al., 1997) that ultimately led to its verification in core obtained from a slanted well. This work describes the results of a follow-up high frequency (1 to 10 kHz) crosswell survey that was designed to illuminate the fracture by air injection into the fracture. Zero-offset P-wave crosswell transmission and reflection measurements conducted during air injection showed a large decrease in the amplitude of the transmitted wave (approximately 10 times reduction at 3 kHz), and a smaller increase in the amplitude of the reflected wave (approximately 1.5 to 5 times increase at 3 kHz). Measurements of the P-wave and an interface wave propagating along the fracture also show a small increase in amplitude during air injection. Analyses of these measurements using numerical boundary element and finite-difference simulations and the importance of including fracture stiffness heterogeneity arising from irregular distributions of air inside the fracture will be presented.

Modeling High-Angle Wells in Laminated Pay Reservoirs

Abstract Productivity improvement and acceleration projects have gained substantially from the success of horizontal well drilling technology. Successful placement of near-horizontal wells in difficult reservoir configurations has become routine. However, not all reservoir situations are amenable to horizontal drilling. Specifically, laminated reservoirs such as thinly bedded turbidites in the Gulf of Mexico (GOM) have been perceived as poor targets. Potentially large reserves are locked in these reservoirs. These laminated turbidite systems have near-zero vertical permeability at the Bouma sequence1 scale and extremely small kv/kh ratios (kv/kh≈0) at the full field, reservoir simulation grid-block scale. In general, a low well count helps minimize development costs. Highly deviated wells (80°≤ θw<90°) cutting the entire sand package may make it possible to obtain both high field production rates and low well counts. Slanted wells have been known to improve productivity of wells with kv/kh≈0. However, the slanted well model given by Cinco2,3 does not predict any improvement in well productivity for such wells. This apparent paradox is reconciled in this paper. Bed thickness, well diameter, and well angle determine the geometric pseudoskin of these thin-bedded sequences. For wells that are nearly horizontal, a simple technique is introduced to calculate the geometric skin without complex modeling. The range of validity of this approximation was determined by comparison with fine-grid simulations.

A Single-Phase Wellbore-Flow Model for Horizontal, Vertical, and Slanted Wells

Summary In this paper, a single-phase wellbore-flow model is presented that incorporates not only frictional, accelerational, and gravitational pressure drops, but also the pressure drop caused by inflow. The new model is readily applicable to different wellbore-perforation patterns and well completions, and can be easily incorporated into reservoir simulators or analytical, reservoir-inflow models. It is found that the influence of either inflow or outflow depends on the flow regime present in the wellbore. For laminar wellbore flow, wall friction increases because of inflow but decreases because of outflow. For turbulent wellbore flow, inflow reduces the wall friction, whereas outflow increases the wall friction. New wall-friction-factor correlations for wellbore flows have been developed that can be applied to determine the wall-friction shear and the frictional pressure drop for either inflow (production well) or outflow (injection well) and for either laminar or turbulent flow regimes. Calculation results show that the accelerational pressure drop may or may not be important compared with the frictional component, depending on the specific pipe geometry, fluid properties, and flow conditions. It is recommended that the new wellbore-flow model be included in wellbore/reservoir coupling models to achieve more accurate predictions of pressure drop and inflow distribution along the wellbore, as well as the well production or injection rates.

Improved Design of Rod Pump Valves For Thermal And Horizontal Wells-Laboratory And Field Results

Abstract This paper presents results from a multi-participant project conducted by AOSTRA, ARC and industry to improve rod pumping efficiency for thermal and non-thermal oil fields in Alberta. It describes experimental and theoretical investigations on the hydrodynamics of rod pump valves that resulted in improved valve design and increased field production rates; and shows that, two of the most frequent problems encountered in the field are associated with sand and gas/steam inflow and may be alleviated through a better design of pump valves. These problems were examined in the laboratory (ARC) by testing ball-valve hydrodynamics at different GOR and inclination angles. Nineteen different valve designs were investigated using two laboratory facilities. Visual observations regarding critical GOR and inclination angles and quantitative measurements of pressure drop at different pump rates and fluid viscosity were obtained. A diagram, in which measured drag coefficient was plotted versus Reynolds number, was used to capture the steady and unsteady behaviours of the cage-ball systems. This diagram provided a basis for improving valve design. Following discussions of the laboratory findings with the project participants (field operators and manufacturers), and at the instigation of one particular manufacturer, a new valve design (HIVAC) was completed, manufactured and field tested at numerous sites. The field test results showed a significant increase in flow compared to conventional API valves previously used at the same sites. Introduction The design and operation of sucker rod operated bottom hole oil pumps, used in 80 – 90% of artificial lift wells, reached a mature stage during the period 1970 – 1980(1).Improved diagnostic tools for evaluating their performance appeared during the 1980s. These tools included automated dynamometer cards that aided rapid and relatively inexpensive de-convolution and interpretation of load-stroke diagrams(2,3). During the last decade, the development of heavy oil reservoirs in Alberta, Saskatchewan, and Venezuela and the widespread use of horizontal and deviated wells for both conventional and heavy oil reservoirs has imposed additional constraints on sucker rod pump applications. In Alberta, thermal projects have always experienced difficulties with pumping operations. In 1988, a survey conducted by the Alberta Department of Energy-Oil Sands and Research Division (formerly AOSTRA) found that the most common problems encountered were pump seizure (customarily related to sand-laden fluids), and pump inefficiencies due to steam and non-condensible gases(4). A multi-disciplinary team consisting of ADOE-OSRD, ARC, eight major field operators and four rod pump manufacturers in Alberta was formed to address those problems. Although the major objective was to improve existing thermal pumping technology, more general applications to horizontal well and high gas/oil ratio situations were put at a high priority. An overview of the program and its major laboratory achievements during 1988 – 1991 has been discussed elsewhere(4). This paper describes further laboratory observations on valve hydrodynamics with conventional and slanted wells obtained during 1991 – 1992, as well as significant field results achieved using a novel valve design. Equation 1 (available in full paper)

An integrated approach for characterizing fractured reservoirs

Abstract Experience has shown that fractures and faults within a given array are not all equally conductive or well-connected. To investigate new techniques for locating conductive fracture flow paths, a series of high resolution (1 to 10 kHz) crosswell and single well seismic surveys and interference tests were conducted in a shallow five spot well array penetrating a fractured limestone formation. Two inverse approaches for constructing fracture flow models were applied to the interference test data. Both approaches successfully reproduced the transient pressure behaviour at the pumping and observation wells and indicated a preferential fracture flow path between two wells aligned in an east-northeast direction, the dominant direction of fracturing mapped in the area. Crosswell and single well seismic experiments were performed before and after air injection designed to displace water from the fracture flow path and increase seismic visibility. The crosswell experiments showed that replacement of water with gas produces significant changes in the seismic signal. The single well reflection surveys were able to precisely locate the position of the fracture flow path. This location was confirmed by core from a slant well which intersected a single open fracture at the targeted depth.

Fracture detection using crosswell and single well surveys

We recorded high‐resolution (1 to 10 kHz), crosswell and single well seismic data in a shallow (15 to 35 m), water‐saturated, fractured limestone sequence at Conoco's borehole test facility near Newkirk, Oklahoma. Our objective was to develop seismic methodologies for imaging gas‐filled fractures in naturally fractured gas reservoirs. The crosswell (1/4 m receiver spacing, 50 to 100 m well separation) surveys used a piezoelectric source and hydrophones before, during, and after an air injection that we designed to displace water from a fracture zone. Our intent was to increase the visibility of the fracture zone to seismic imaging and to confirm previous hydrologic data that indicated a preferred pathway. For the single well seismic imaging (a piezoelectric source and an eight‐element hydrophone array at 1/4 m spacing), we also recorded data before and after the air injection. The crosswell results indicate that the air did follow a preferred pathway that was predicted by hydrologic modeling. In addition, the single well seismic imaging using vertical common depth‐point (CDP) gathers indicated an anomaly consistent with the anomaly location of crosswell and hydrologic inversion results. Following the field tests, a slant well was drilled and cored to confirm the existence and nature of the rock associated with the seismic anomalies. A vertical fracture was intersected within less than 1 m of where the seismic results had predicted.

A Generalized 3D Well Model for Reservoir Simulation

Abstract Well modelling plays an important role in reservoir simulation. Commonly used well models are based on the 2D analytical pressure solution (radial flow) and on an "adequate" numerical productivity index calculation. These models applied to 3D simulations may give erroneous results, especially while modelling undulating wells (slanted wells), multi-lateral wells, finite-length horizontal wells or partially penetrating vertical wells. The main reasons are the lack of 3D pressure solution and the inaccurate flow calculation near the well. In this paper, the layer potential is introduced for representing the 3D pressure distribution of the steady-state flow in the vicinity of wells. The flow approximation is improved by modifying the near well transmissibilities, taking into account this 3D pressure solution. This new well model is valid for any well configuration and allows to describe accurately 3D well behaviour.

Modelling of Undulating Wellbore Trajectories

Abstract A technique for the efficient modelling of horizontal and undulating well trajectories is presented. In order resolve the fluid saturation and pressure, the layer containing the undulating wel1bure is refined in the vertical direction. The undulating wellbore is then represented by a series of discrete, cylindrical well bore segments which arc parallel the principal grid directions. The pressure drop and liquid holdup within the wellbore are determined through a material balance equation and multiphase pipe flow correlation. Several examples illustrating the application of this method are given for the modelling of undulating well trajectories. A comparison between the source/sink model and the discretized wellbore model for undulating wells is made. It is demonstrated that the discrelized wellbore model should be used when the total wellbore pressure drop is comparable to the drawdown pressure. The effect of capillary pressure is also examined for several different well trajectories. Finally, the effect of well trajectory for the production from a thin oil column with bottom water drive and a gas cap is examined. Introduction Interest in horizontal well has increased dramatically in recent years due to improved drilling technology and increased efficiency and economy of oil recovery operation. This improvement results from the extensive contact between the reservoir and the horizontal well giving rise to lower fluid velocities around the wellbore, while providing economical total flow rates. There are three methods used to represent horizontal wells in reservoir simulation. The first approach is the source/sink representation. This method is applicable when the frictional pressure drop along the wellbore is small compared to the well drawdown pressure(1). Furthermore the line source/sink method can yield erroneous results when wellbore backflow occurs (2) or when the reservoir permeability is high due to the presence of fractures. The second approach is very comprehensive and requires the simulations solution of equations of the conservation of mass, momentum and energy in the wellbore together with the reservoir bore and its vicinity is important for accurate predictions. Because of the comprehensive treatment of the wellbore, the computational cost of this approach is high and therefore may be prohibitive simulations it may not be necessary to model the detailed flow phenomenon in the wellbore. A good approximation of the pressure drop phase saturation and composition distribution in the wellbore usually surfaces. The third approach termed "the diserenzed wellbore model", couples the wellbore and reservoir flow equations by edaciously casing the wellbore flow equation in a form similar to the reservoir flow equations. Thus, efficient numerical techniques that have been developed for reservoir simulation ncan be used to accurately model the wellbore flow. In reality, horizontal wells are not perfectly horizontal and can have complex well trajectories. These well trajectories can result in either slanted or undulating wells. For typical cases the horizontal well trajectory can vary by as much as ±5 m. Figure 1 shows a schematic representation of such an undulating well.

Simple Approach to the Cleanup of Horizontal Wells With Prepacked Screen Completions

Openhole completions with prepacked screens are increasingly the completion of choice for horizontal wells requiring sand control. For maximum productivity from these wells, preventing mud damage to the formation and the screen or removing it before bringing the well onto production is vital. A common industry approach to this problem is to displace the drilling mud to an aqueous clear fluid before production, typically followed by a breaker fluid. This paper details an alternative approach: bringing the well on without cleanup. The paper outlines the decision-making process, shows how the drill-in-fluid ad cleanup operations are designed, explains how laboratory resting can be used to support the design philosophy, and highlights that quality control of the mud system while drilling is critical to the success of such a well. Case histories in two very different reservoirs are presented that illustrate the success of this approach.

Wear-corrosion-resistant materials for mechanical components in harsh environments

In pumping the deviated and slant oil wells, many commonly used materials are readily attacked by the combined effect of mechanical wear and the harsh environment of the bottom hole. Three groups of new materials that include ceramics, alloys and hard coatings were evaluated for the downhole application. Two sets of tests, which involved scaling and corrosion for the first, and wear for the second, were carried out in parallel. The wear tests were further divided into reciprocating sliding and impact/fretting, in dry and in 2% sand slurry conditions. The investigation identified the wear mechanisms involved. The test results showed that a steel alloy with a titanium carbide composite in a martensitic matrix, and both nitrided and chrome-plated carbon steels could provide good wear resistance for both dry and slurry conditions.

Sand Control in Horizontal Wells in Heavy Oil Reservoirs

Abstract Horizontal wells are of great interest to most oil companies operating inheavy oil fields. Due to more extensive contact with the reservoir, horizontalwells allow fluid flow at lower fluid velocities yet providing total flowswhich are economic. While horizontal wells have the potential to make many moreheavy oil reservoirs economic, one of the most pressing concerns has been to beable to complete the wells properly. Unfortunately, likely candidates ofhorizontal wells are mostly "quicksand" type formations and thecritical velocities of sand in a wellbore is extremely low. Consequently, sandis very likely to enter the horizontal wellbore if not preventive measure istaken. Problems of sand production in a horizontal well is more complicatedthan in a vertical well due to difficulty in cleaning sands in horizontalwellbores. The present study discusses the problems of sand production in ahorizontal well and offers production in a horizontal well and offersrecommendation in controlling them. Physical simulation of the top part of thehorizontal well showed that both gravitational and inertial forces helpminimizing sand production. This will mean that increasing flow rates willdecrease sand production. Experimental evidence showed that production. Experimental evidence showed that selection of liner diameter and wire spacingare important parameters in controlling sand productions. Permeability damagedue to particle productions. Permeability damage due to particle mixing in theannulus was quantified. It was shown that smaller annulus is of more importancein the case of smaller wire spacing, lower oil viscosity and thinner payzone. Introduction Sand production is considered to be one of the major problems that haveperplexed the petroleum industry. Every year the petroleum industry spendsmillions of dollars in sand cleaning, repair problems related to sandproduction and lost problems related to sand production and lost revenues dueto restricted production rates. Consequently, sand control has been a researchtopic for over five decades. Uncontrolled sand production is very expensive dueto additional production is very expensive due to additional operating expenses(such as pump change, well cleanup, etc.), lost revenues, and creation ofpotentially hazardous situation. These problems are potentially hazardoussituation. These problems are magnified for horizontal or slanted wells forwhich well cleaning technique is not trivial. Additional expenses associatedwith sand production include clean out and disposal of sand and workover coststo return the well to production. The lost revenue due to restricted orcompletely shut in production is often a hidden expense and not alwaysproduction is often a hidden expense and not always considered in economiccalculations. Most of the early research work conducted by petroleum industry involved indesigning largest petroleum industry involved in designing largest practicalsizes of gravels and liners with the practical sizes of gravels and liners withthe notion that this will also lead to highest production rates. For manyyears, the philosophy of production rates. For many years, the philosophy of" if all sand production is stopped, the fluid production will bestopped" seemed to dominate the production will be stopped" seemed todominate the petroleum industry. Recent research efforts, petroleum industry. Recent research efforts, however, have focused on completion and control whilemaintaining highest well productivity. Sand control Methods Sand control methods may be classified as mechanical, chemical andmechanical/chemical. Mechanical methods of sand control prevent sand productionby stopping the formation with liners, production by stopping the formationwith liners, screens or gravel packs. Larger formation sand grains are stopped, and they in turn stop smaller formation sand grains. Chemical control methodsinvolve in injecting consolidating materials into the formation to cement thesand grains. A combination of plastic consolidated gravel and screen may beused to controls and in some wells to provide increased stability to the pack.provide increased stability to the pack. Reasons For Sand Production Sand production occurs when the stresses on the formation exceeds thestrength of the formation.

Transient Pressure Behavior off Commingled Reservoirs

Summary This paper presents a new general analytic formulation for pressure-transient behavior of commingled systems (layered reservoirs without crossflow). The formulation includes the effects of surface and downhole flow-rate variations and of wellbore storage resulting from the wellbore volume's location below the flow-rate measuring point (at any location in the wellbore, including the surface and sandface). The method can be applied to a variety of layered reservoirs. Each individual subzone (reservoir) in the system can be different, with different initial and outer-boundary conditions, and each zone can start to produce at a different time. The well completion for each layer can also be different. New Laplace-domain solutions are presented for partially penetrating slanted wells and partially penetrated wells with and without a gas cap. The solution for slanted wells is based on that of Cinco-Ley et al. but includes the correct effective wellbore radius for the case of an anisotropic formation. Solutions to a few selected commingled systems are also presented to explore the application of the formulation.