Interwell Space Research Articles

Concepts And Opportunities In Using Horizontal Wells In High Quality Reservoirs

Abstract A considerable fraction of Alberta's, and the world's, oil has been produced from high quality reservoirs dominated by gravity drainage. However, almost all of these reservoirs in North America have been completely flooded with gas, solvent or water, and are nearing economic limits with vertical wells. Often reservoir simulations show little economic incentive to drill horizontal wells for incremental recovery of sandwich or attic oil, because very high permeability minimizes cone heights. Nevertheless, many of Husky's horizontal wells, which have been produced from these types of reservoirs, have been extremely successful(1). Heterogeneity The most obvious reason for an unexpected success in high quality reservoirs is the effect of higher than anticipated heterogeneity on oil drainage. Even though average permeability at a well may be in the darcy range, the consequence of low permeability layers on the cone shape C3n be extreme (Figure 1). The existence and effect of these low permeability sheets is often a surprise, because log, core and production data alone do not provide one with the full story of heterogeneity and fluid flow in the reservoir. Estimating the lateral extent of tight zones shown on logs is difficult when interwell spacing is less than the extent of these tight zones. Also, many thin low permeability layers are not clearly identified by most logging tools. Stylolites, and other very thin impermeable zones, are often avoided in selection of core for analysis, but can extend far enough laterally to seriously restrict vertical fluid flow(2). A simulation history match of production data can be accomplished using a high residual oil saturation, instead of a representation of bypassed oil zones caused by reservoir heterogeneity. Therefore, a very careful analysis of log, core and production data is required to identify heterogeneities. Other methods which can help one determine the location and extent of permeability "barriers" are pressure interference testing, interwell tracing, gathering fluid type and saturation data from infill wells and testing intervals of existing wells. Lateral heterogeneity can also play a major role in oil drainage. For example, porosity stringers at the margin of a reservoir are often poorly drained (Figure 1). The location of these stringers can sometimes be determined with more advanced seismic techniques. Mechanics of Interval Isolation Another reason for horizontal well success is simply the challenge of producing from a thin oil interval with a vertical well. Formation damage, poor cement, and equipment malfunctions all contribute to hinder vertical well production (Figure 2). Recent technological advances have reduced the severity of these problems in some newly drilled and completed wells, however, many high quality reservoirs are being produced through older wells. Low Drawdown, Wellbore Crossflow and Fluid Separation Horizontal, and in some cases vertical, wells can produce at economic rates from very high penneability zones at almost no drawdown. Producing 100 m3/d of light oil from a 1,000 m long horizontal well in a massive reservoir with 2 darcies permeability will result in a drawdown of only 3 kPa3.

High‐resolution crosswell seismic experiment with a large interwell spacing in a west Texas carbonate field

A high‐frequency crosswell seismic dataset acquired in a west Texas carbonate field has demonstrated the feasibility of the technique with a large interwell spacing. Two crosswell profiles were acquired with a well spacing of 1500 ft (460 m) and over a depth interval from 7700 ft (2350 m) to 9600 ft (2930 m) using a piezoelectric bender source. The data quality is profile and depth dependent, with the ambient noise level at the receiver position being the most important factor. Noise levels and noise characteristics among three wells were significantly different. Tube waves and gas‐ and fluid‐movement in the borehole are the dominant noise sources found in the data set. Two lithologic properties, attenuation and transmission loss controlled the data quality. Good quality and high frequency (>1000 Hz) data were acquired over most of the survey interval which contains massive limestones. However, we could not acquire any useful data within the shale layers. Transmission losses and the effects of the source radiation pattern that occurred at interfaces with large impedance contrasts limited the aperture of the useful data. There were two critical issues encountered during the reflection imaging process: (1) sparse trace spacing and poor coherency of the reflection events in common‐source gathers degraded the image in a region near the receiver well; and (2) possible lateral velocity heterogeneity in the medium and limited aperture made it difficult to build an appropriate velocity model for reflection imaging.

A 3-D seismic case history evaluating fluvially deposited thin‐bed reservoirs in a gas‐producing property

We conducted a study at Stratton Field, a large Frio gas‐producing property in Kleberg and Nueces Counties in South Texas, to determine how to best integrate geophysics, geology, and reservoir engineering technologies to detect thin‐bed compartmented reservoirs in a fluvially deposited reservoir system. This study documents that narrow, meandering, channel‐fill reservoirs as thin as 10 ft (3 m) and as narrow as 200 ft (61 m) can be detected with 3-D seismic imaging at depths exceeding 6000 ft (1800 m) if the 3-D data are carefully calibrated using vertical seismic profile (VSP) control. Even though the 3-D seismic images show considerable stratigraphic detail in the interwell spaces and indicate where numerous thin‐bed compartment boundaries could exist, the seismic images cannot by themselves specify which stratigraphic features are the flow barriers that create the reservoir compartmentalization. However, when well production histories, reservoir pressure histories, and pressure interference tests are incorporated into the 3-D seismic interpretation, a compartmentalized model of the reservoir system can be constructed that allows improved development drilling and reservoir management to be implemented. This case history illustrates how realistic, thin‐bed, compartmented reservoir models result when geologists, engineers, and geophysicists work together to develop a unified model of a stratigraphically complex reservoir system.

Simulation of Horizontal Wells For Winter Cummings Sand Pool

Abstract To determine the optimum spacing for the development of heavy-oil-over-water reservoirs by an array of horizontal wells, a quick and inexpensive but rigorous two-dimensional (2-D) cross-section simulation model containing 340 cells in an element of symmetry was developed. Its validity was tested against a 4,760 cell three-dimensional (3-D) model. The 2-D model was calibrated by history matching a horizontal well with 17,000 m3 of fluid production. At the low flow rates typical in heavy oil applications (governed by wellbore inflow performance, lifting system capacity and sand control considerations), the pressure drop along the horizontal wellbore from "toe" to "heal" is insignificant, rendering acceptable accuracy from the 2-D model. The fine grid system in the 2-D- model also permitted the analysis of the development of the water crest with time. Additionally, the effects of reservoir stratification, standoff from the water-oil contact, production rate, oil viscosity, relative permeabilities and degree of pressure support from the aquifer were investigated. Based on-the study results, optimum interwell spacing was determined for the Winter Cummings Sand Pool. Although this model was applied to a particular reservoir, it is app1icable to any oil-over-water reservoir producing at relatively low rates, for spacing determination and performance prediction. Introduction The Winter Cummings Sand Pool is located in Townships 42 and 43, Range 25, West of the Third Meridian, which is about 100 kilometers southeast of L1oydminster, as shown in Figure 1. The pool was discovered in 1979 by the drilling of well 13-27-42-25W3 which encountered an 18 m oil column over 10 m of water (Figure 2). An encouraging initial production rate of up to 6 m3 per day from well 13-27 led to further drilling until early 1983. When the 14th well, 16-29, which was drilled in virtually the centre of the field, encountered no oil column at all, further field development was suspended and a geological review was initiated. This, together with the introduction of the National Energy Policy, ended further development with 13 producers and one cased potential service well in place (Figure 3). After 1983, the wells were produced at rates of about 4 to 5 m3 of oil per day before water breakthrough, which occurred after 300 to 3,000 m3 of oil production. With the oil price collapse in 1986, the entire pool was shut-in due to poor economics. At this time, cumulative oil production was only 23,000 m3 or 0.02% of the original oil-in-place. FIGURE 1: Location of Winter Pool. (Available in full paper) Horizontal Well Pilot - Phases I and II Although the horizontal well alternative was considered as early as 1984, the high capital investment, in combination with the technical uncertainty at the time, led to a prolonged period of evaluations, re-evaluations and negotiations culminating in a farm-out agreement involving a pilot consisting of a minimum of two and a maximum of five horizontal wells, over a two-year period. The first phase of the pilot involved two wells (A6-32 and B14-28-42-25W3M) and the second phase involved three wells (B7-29, A2-33 and A7-32-42-25W3M).

Tunneling between a pair of parallel Hall droplets.

In this paper, we examine interwell tunneling between a pair of fractional quantum Hall liquids in a double-quantum-well system in a tilted magnetic field. Using a variational Monte Carlo method, we calculate moments of the intra-Landau-level tunneling spectrum as a function of in-plane field component ${\mathit{B}}_{\mathrm{R}}$\ensuremath{\parallel}and interwell spacing d. This is done for a variety of incompressible states including a pair of \ensuremath{\nu}=1/3 layers ([330]), a pair of \ensuremath{\nu}=1/5 layers ([550]), and Halperin's [331] state. The results suggest a technique to extract interwell correlations from the tunneling spectral data.

Magnetorotons and the fractional quantum Hall effect in double-quantum-well systems.

The collective modes of the \ensuremath{\nu}=1/2 state in double-quantum-well systems are analyzed within the framework of the single-mode approximation. The dependence of these modes on the interwell spacing is discussed. The derivation of the plasma sum rules for the two-component classical plasmas corresponding to the unpolarized [mmn] states is derived in the Appendixes.

Effective Application of Steam Assisted Gravity Drainage of Bitumen to Long Horizontal Well Pairs

Abstract A recent field test of the Steam Assisted Gravity Drainage (SAGD) process at the Alberta Oil Sands Technology Research Authority (AOSTRA) Underground Test Facility (UTF) has proven that the process mechanisms work in the field as expected from previous laboratory, analytical, and numerical work. The UTF test used well pairs that were completed for only about 5 m, however, as compared to lengths of several hundred metres which will be required for commercial application. Accordingly, the UTF Phase B test currently under construction will use wells with a full 500 m of completion. This paper reviews the design and operating requirements that have been developed to ensure that the full lengths of the Phase B well pairs contribute to bitumen recovery, i.e. that the production rates will scale up in proportion to length. The discussion proceeds from the conditions required to initiate drainage at a given location along the well pair, to the means of establishing and maintaining such conditions at every location. Numerical examples show that, for typical formation permeabilities, start-up can be achieved with thermal conduction and gravity alone, two highly predictable phenomena. This leads to consideration of design and operational requirements to ensure that conduction heating is maintained on the one hand, and gravity is not defeated (by adverse pressure gradients) on the other. In summary these are:the well pairs must be drilled so that the interwell spacing remains within specific tolerances;the liner and tubing must be large enough, relative to the completion length and expected formation productivity, so that pressure gradients are kept below certain values, anda full length tubing string must be combined with correct operating policy to ensure that the full lengths of both injection and production liners are kept hot throughout the life of the well. Introduction Butler et al(1), and Edmunds et al(2) have previously described the mechanics of two dimensional SAGD to a pair of horizontal wellbores. The recent Phase A test of SAGD at the AOSTRA UTF(3) showed that the process mechanisms work in the field as expected from previous laboratory, analytical, and numerical work. Phase A well pairs were completed for only about 55 m, however, whereas economic commercial application requires several hundred metres of active completion. AOSTRA is accordingly proceeding with a Phase B Test of three long well pairs, with 500 m completed length. In a reservoir of immobile bitumen, fluid mobility must be artificially FIGURE 1: Three dimensional start-up of a long well pair. created between a well pair before SAGD can proceed. With reference to Figure 1, it should be easy to force communication between an injector and producer over at least one section of a long well pair, but it is less clear how the remainder of the pair can be made to follow in a reasonable time, say a few months. Long delays will incur very significant economic penalties; not only will the Calendar Day Oil Rate (CDOR) be reduced, but also, because a longer time will be required to recover the same amount of oil, the Stearn/Oil Ratio (SOR) will be increased.

FRACTAL GEOMETRY, RESERVOIR CHARACTERISATION AND OIL RECOVERY

Reservoir heterogeneity is a dominant factor in determining large-scale fluid flow behaviour in reservoirs. Engineering estimates of oil production rates need to acknowledge and incorporate the effect of such heterogeneities. This work examines the use of fractal-based scaling techniques aimed at characterising heterogeneous reservoirs for simulation purposes. Well log data provide suitable fine-scale information for estimating the fractal dimension of reservoirs as well as providing known end- point data for interwell property value interpolation. Fractal techniques allow this interpolation to be performed in a manner which reproduces the same correlation structure as that found in the original well logs. Conditional simulation in these property fields allows the interaction between reservoir heterogeneity and fluid flow to be studied on a range of scales up to the interwell spacing. Analysis of results allows the calculation of effective reservoir properties which characterise the reservoir in terms of large-scale performance.

An Improved Design of the Subsea Atmospheric System

Summary The subsea atmospheric system (SAS) is part of a deep-water production system designed, built, and tested onshore and at sea. Recently, an effort was made to improve this earlier prototype version of the SAS and to extend its application into deeper waters. This paper discusses the resulting improved design. It describes the updated major hardware components of the SAS, its principal subsystems, and installation procedures. Introduction The first SAS was designed in 1969, constituting the basic component of a complete deepwater production system intended to handle field production from wellhead through offloading. A full-scale prototype of the SAS was fabricated and tested onshore in 1971. The following year it was installed in the Gulf of Mexico; it operated intermittently subsea with live oil production, and was retrieved in 1976. production, and was retrieved in 1976. The complete system (Fig. 1) contains five basic components:(1)the SAS;(2)the subsea atmospheric riser manifold, designed to manifold production from several SAS units and to provide a base for connecting with production from several SAS units and to provide a base for connecting with the production riser;(3)flowline bundles, consisting of as many as a dozen lines, to connect each SAS to the riser manifold;(4)a compliant production riser system; and(5)a floating production facility, which production riser system; and(5)a floating production facility, which contains equipment for oil/gas separation, optional gas and water injection, and provision for oil storage and offloading to tankers. The SAS consists of four major hardware elements (Fig. 2). A subsea template serves as a base through which peripheral wells are directionally drilled to selected subsurface targets. Drilling is conducted with floater rigs; then master valve and wellhead connector assemblies (MVA's and WCA's) are installed sequentially in a wet hyperbaric environment. These wet split Christmas trees connect the wells to the subsea work enclosure (SWE), which is centrally attached to the base template. In contrast to the wet elements, the SWE provides a dry environment at atmospheric pressure on the seafloor, housing the control valves, chokes, piping, and instruments required for automated producing operations. It contains the necessary mechanical internals and supporting subsystems to function as a subsea mani folding station, while providing for accessible crew entry by means of submersibles for system maintenance. Major SAS Hardware Components Base Template The base of the SAS serves as a multiwell template for closely spaced directional drilling, and provides both support and alignment for the elements connected to it. Circular geometry was selected (Fig. 2) where nine wells are accommodated, equally spaced around the periphery of the template on a common radius. The basic size of the periphery of the template on a common radius. The basic size of the template is governed by the number of wells, the minimum required spacing between wells, and the size of the work enclosure. An interwell spacing of about 15 ft [4.6 m] has been adopted, slightly more than the minimum required for no overlap of the blowout preventer (BOP) envelope. The base template is constructed with structural pipe (Fig. 2). It consists of two main sections-a lower support structure and an upper bumper structure. The lower section provides the predominant structural support for the SWE, BOP stack, MVA, WCA, and subsea flowline connections. It contains 30-in. [76.2-cm] horizontal tubulars for seafloor support, and vertical tubulars that serve as well-conductor guides. The upper section of the base template contains 20-in. [50.8-cm] pipe, and extends more than 30 ft [9.1 m] above the lower section. It pipe, and extends more than 30 ft [9.1 m] above the lower section. It serves two essential purposes:to protect the well assemblies and a major portion of the installed work enclosure andto aid the alignment and guidance of the SWE during its installation. This upper bumper structure divides the base template into wedge-shape segments or bays. One bay functions as an alignment slot for the flowline connector system on the subsea enclosure, and the others serve as locations for subsea wells. Design provisions also were incorporated in the base template to assist in the maintenance and workover of other components. SWE Hull The SWE hull projects features that are distinctive and peculiar to the SAS. Its geometric configuration, a vertically oriented peculiar to the SAS. Its geometric configuration, a vertically oriented stepped cylinder, has long been identified with the SAS prototype and was basically preserved in this improved design. Fig.2 shows that the main chamber, called the "service section," is essentially a large-diameter cylindrical band capped by hemispherical ends. The lower hemisphere is attached to a skirt structure that helps support the hull and its internal contents. A smaller-diameter cylinder, likewise capped by a hemisphere, attaches integrally to the top of the main chamber to form the "control section." JPT p. 443

Effects of Dispersion and Dead-End Pore Volume in Miscible Flooding

Abstract The design of the solvent slug size for a miscible flood process can be improved with data on holdup (or capacitance process can be improved with data on holdup (or capacitance effects) and dispersion of the solvent slug in the reservoir. A modified version of the Coats-Smith dispersion-capacitance model and an improved solution method for the model were used to study dispersion and capacitance effects in cores. The velocity dependence of the model parameters is shown. A correlation is developed for estimating effective dispersion coefficients for field application. The method described provides a means for characterizing the properties of dispersive mixing and microheterogeneity of reservoir properties of dispersive mixing and microheterogeneity of reservoir cores and aids in the design of the volume of solvent for miscible floods. Introduction The amount of solvent that must be injected is a critical factor in the success of a miscible flood. Because of the cost of miscible solvents such as carbon dioxide or rich gas, slug processes generally are used. If the solvent slug used is larger processes generally are used. If the solvent slug used is larger than necessary, the solvent cost will be increased without compensatory increases in oil recovery. If too small a slug is used, some of the oil that could have been moved will be left behind. The slug size required is affected by many variables, including reservoir geometry, interwell spacing, gravity effects, mobility ratios, etc. Slug degradation is caused by mixing (by dispersion) of solvent with oil at the leading edge of the solvent bank and with chase fluid (for example, dry gas) at the trailing edge. Trapping of oil and solvent in microscopic heterogeneities (regions of dead-end pore volume or relatively stagnant flow) also contributes to the mixing-zone growth. This trapping, known as capacitance may be caused by rock heterogeneities or by shielding of oil and solvent by water films. This paper is concerned with predicting solvent slug requirements in an idealized linear system where gravity, mobility ratio, and areal sweep effects are unimportant, but where longitudinal dispersion (mixing at the leading and trailing edges of the bank) and capacitance effects are significant. An example might be a miscible displacement in the pinnacle reef formations of Alberta. A prediction of the effects of dispersion and capacitance was needed for the design of a miscible flood of this type. The oil-column height was about 350 ft, and the flood advance rate was to be downward at 0.0384 ft/D. The oil/solvent viscosity ratio of 10 was unfavorable; however, it was expected that the unfavorable mobility effects would be largely compensated for by the stability effects of gravity at the low flow rate. Published data relating to similar reservoirs indicated that "stagnant volume" that could cause trapping and degradation of the solvent slug might be as much as 10 percent of the reservoir volume. Based on these data, preliminary calculations were made using the Coats-Smith dispersion-capacitance model to predict the mixing-zone profiles. The results indicated that this level of stagnant volume might cause the solvent requirement to be increased by 30 to 90 percent over the amount predicted by a simple dispersion model without capacitance effects if the peak solvent concentration in the enriched gas bank did not drop below 99 percent throughout the life of the flood. Coats and Smith indicated that tests in short cores would show extended mixing zones if capacitance effects were present, but that if the magnitude of the transfer group M(D) = M(L)/u was large (as it would be in a field situation, where L may be very large), the influence of capacitance would be minimized. The prediction of a 30- to 90-percent increase in solvent requirements for the case described above prompted a review of methods for measuring capacitance effects and a search for a more convenient method for predicting the severity of capacitance effects in field application. predicting the severity of capacitance effects in field application. An improved method for modeling data from short core tests was developed, and experimental work was performed to investigate the factors influencing the capacitance-model parameters. SPEJ P. 219

Transient Pressure Testing of Fractured Water Injection Wells

Abstract Excessive injection pressures in water injection wells may create deeply penetrating fractures, or may open up existing reservoir fractures. If these fractures are oriented toward offset producing wells, oil recovery at injected water breakthrough and ultimate recovery will be impaired. A method of calculating fracture lengths from pressure fall-off test data is presented. The method is based on a linear flow model that simulates conditions present during the early-time period after shutting in an injection well. Fracture lengths can be calculated directly if formation permeability is known. A graphical technique is presented that provides fracture lengths based on permeabilities calculated from normal fall-off tests, where those permeabilities are adjusted for flow geometry. Test data from four injection wells and results obtained from applying the method to these wells are discussed. Introduction Rates of water injection into nonstimulated wells in low permeability reservoirs frequently fall below economically desirable levels. Therefore, some form of stimulation such as hydraulic fracturing often is performed on these wells. Usually these fractures penetrate a short distance from the well-short as compared with interwell spacing and therefore should not create problems of water channeling to offset producing wells. In the past, some operators have been tempted to increase injection pressures continually to maintain a specified injection rate, But pressures cannot be increased indefinitely. Field data indicate that continued injection above fracture opening pressure can cause excessively long fractures to approach between well distances. If these long fractures intersect or closely approach offset producing wells, premature water breakthrough can result. It is difficult to seat effectively these fractures by various workover procedures after premature water breakthrough has occurred. This paper describes testing procedures that are potentially capable of detecting premature water breakthrough before it occurs. Knowledge of fracture lengths and fracture opening pressures can assist field engineers in selecting optimum operating conditions for water injection wells. Fracture lengths should be calculated from pressure fall-off tests on injection wells, and maximum permissible injection pressures should be determined from step-rate injectivity tests. Equipped with this information, the field engineer is in a better position to recommend for a particular injection well the optimum operating conditions that will lessen the chances of channeling to offset producers. Historically, pressure transient tests have been conducted primarily on producing wells and analysis procedures have been based on radial flow concepts. Several authors have suggested that these same procedures be applied to tests conducted on water injection wells. This application is justified for wells that are not connected to extensive fracture systems. However, if the formation is severely fractured, the interpretation methods must be modified. Theory and Definitions Three flow-system geometries are considered in analyzing injection well test data. These various geometries are applicable during specific time intervals of transient pressure tests. Schematic drawings of the flow models, and the time intervals over which they are applicable, are shown in Fig. 1 in the chronological order that they are applied to the pressure response of water injection wells in fractured formations. The very early response is simulated by an infinite linear system as shown in Fig. 1A. This representation permits the calculation of matrix surface area exposed to the fracture. The model shown in Fig. 1B is identical with the one studied by Russell and Truitt. They evaluated the transient pressure response of this vertically fractured system by finite difference techniques. The results were presented as tabulations of dimensionless pressure drop functions for a range of fracture lengths. A semilog plot of these data shows that the apparent matrix permeability can be related to the true matrix permeability by a simple exponential function. Their adjustment factor is used in this paper to improve the accuracy of matrix-permeability and fracture-length calculations.