Analysis of Interference Tests with Horizontal Wells

2005 ◽  
Vol 8 (04) ◽  
pp. 337-347 ◽  
Author(s):  
Mohammed N. Al-Khamis ◽  
Erdal Ozkan ◽  
Rajagopal S. Raghavan
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Observation Point ◽  
Integral Solution ◽  
Observation Well ◽  
Vertical Wells ◽  
Exponential Integral ◽  
Test Analysis ◽  
Interference Test ◽  
Interference Tests

Summary One of the common assumptions in horizontal-well interference-test analysis is to ignore fluid flow in and out of the horizontal observation well and represent it by a point. In some cases, the active well is also approximated by a vertical line source. Using a semianalytical model, this paper answers three fundamental questions:• What is the critical distance between the wells to represent the horizontal observation well by an observation point?• Where should the observation point be placed along the horizontal well?• Under what conditions may the active well be approximated by a vertical line source and the exponential integral solution be used to analyze observation-well responses? Two correlations are presented to simplify the analysis of horizontal-well interference tests. Example applications are presented, and error bounds are documented. Introduction Analysis of horizontal-well interference tests is an extremely difficult problem because the lengths, orientations, locations, and distances between wells need to be considered. One of the assumptions used to make the horizontal-well interference-test analysis a tractable problem is to ignore the flow pattern that results because of the existence of the horizontal well and to treat the horizontal observation well as an observation point. It also has been suggested that if the distance between the two wells were sufficiently large, then the active horizontal well could be replaced by a vertical well. In this case, the observation-well responses may be approximated by the exponential integral solution, and the analysis is reduced to the conventional interference-test analysis between vertical wells. For the application of the approximate analytical techniques, two questions need to be answered. The first question is whether the distance between the two horizontal wells is large enough for the geometry of the wells to be ignored. Malekzadeh investigated this question by considering the interference between a horizontal active well and a vertical observation well in an isotropic reservoir. Because anisotropy has a major effect on the pressure-transient responses of horizontal wells, the results of Malekzadeh have limited applicability. In addition, the influence of the geometry of the observation well cannot be deduced from the model used by Malekzadeh. The second question is, where should the equivalent observation point (EOP)be placed in the reservoir if the horizontal well were to be replaced by a vertical well? This question has yet to be addressed in the literature. The EOP is defined as the location at which the pressure recorded at the heel of the horizontal observation well would exist in the absence of the observation well. Because of the lack of theoretical guidance, the physical location of the heel or the center of the observation well is usually chosen as the observation point.1 But such an assumption ignores the fact that fluids enter and leave the horizontal observation well although there is no surface production. Therefore, some disturbance of equipotential lines around the observation well should be expected. Thus, if the horizontal well were to be removed from the system, we may expect the pressure recorded at the heel of the horizontal well to exist at a different location. The location of the EOP would be a function of the variables that determine pressure at the observation well. This work uses a semianalytical model to answer the above questions. The model has been discussed in detail in Refs. 4 and 5 and is capable of considering interference between two horizontal wells in a homogeneous but anisotropic reservoir. Based on the results of the semianalytical model, two correlations have been developed to significantly simplify the analysis of horizontal-well interference tests without sacrificing accuracy. The first correlation provides the location of the EOP, which has not been available in the literature. The second correlation provides information on the distance under which both horizontal wells may be treated as vertical wells and the exponential integral solution may be used to analyze the interference test. Compared with the correlation presented by Malekzadeh, the correlation presented here is more comprehensive because it accounts for the effects of anisotropy, location of the EOP, and relative position of the wells. To assess the adequacy of the correlations, error bounds have been calculated and are documented in this paper. The correlations enable us to analyze horizontal-well interference tests by the single-horizontal-well solutions or by the exponential integral solution. The convenience of the single-horizontal-well models for the regression techniques used in well-test-analysis software becomes clear if the computational complexity of the rigorous horizontal-well interference-test models4,5 is noted (the increase in the speed of computations is usually more than six-fold).

Analysis of Horizontal-Well Responses: Contemporary vs. Conventional

2001 ◽  
Vol 4 (04) ◽  
pp. 260-269 ◽  
Author(s):  
Erdal Ozkan
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Well Test ◽  
Transient Pressure ◽  
Vertical Wells ◽  
Well Test Analysis ◽  
Test Analysis ◽  
Response Models ◽  
In The Beginning ◽  
Well Models

Summary Most of the conventional horizontal-well transient-response models were developed during the 1980's. These models visualized horizontal wells as vertical wells rotated 90°. In the beginning of the 1990's, it was realized that horizontal wells deserve genuine models and concepts. Wellbore conductivity, nonuniform skin effect, selective completion, and multiple laterals are a few of the new concepts. Although well-established analysis procedures are yet to be developed, some contemporary horizontal-well models are now available. The contemporary models, however, are generally sophisticated. The basic objective of this paper is to answer two important questions:When should we use the contemporary models? andHow much error do we make by using the conventional models? This objective is accomplished by considering examples and comparing the results of the contemporary and conventional approaches. Introduction Since the early 1980's, horizontal wells have been extremely popular in the oil industry and have gained an impeccable standing among the conventional well completions. The rapid increase in the applications of horizontal-well technology brought an impetuous development of the procedures to evaluate the performances of horizontal wells. These procedures, however, used the vertical-well concepts almost indiscriminately to analyze the horizontal-well transient-pressure responses.1–14 Among these concepts were 1) the assumptions of a line-source well and an infinite-conductivity wellbore, 2) a single lateral withdrawing fluids along its entire length, and 3) a skin region that is uniformly distributed along the well. It should be realized that for the lengths, production rates, and configurations of horizontal wells drilled in the 1980's, these concepts were usually justifiable. The increased lengths of horizontal wells, high production rates, sectional and multilateral completions, and the vast variety of other new applications toward the end of the 1980's made us question the validity of the horizontal-well models and the well-test concepts adopted from vertical wells. The interest in improved horizontal-well models also flourished on the grounds of high productivities of horizontal wells. It was realized that, in many cases, a few percent of the production rate of a reasonably long horizontal well could amount to the cumulative production rate of a few vertical wells. In addition, the productivity-reducing effects were additive; that is, a slight reduction in the productivity here and there could add up to a sizeable loss of the well's production capacity. Furthermore, the low oil prices also created an economic environment where the marginal gains and losses in the productivity may decisively affect the economics of many projects. In the beginning of the 1990's, a new wave of developing horizontal-well solutions under more realistic conditions gained impetus.15–25 As a result, some contemporary models are available today for those who want to challenge the limitations of the conventional horizontal-well models. Unfortunately, the rigor is accomplished at the expense of complexity. Furthermore, even when a rigorous model is available, well-established analysis procedures are usually yet to be developed. This paper presents a critique of the conventional and contemporary horizontal well-test-analysis procedures. The main objective of this assessment is to answer the two fundamental questions horizontal-well-test analysts are currently facing:When is the use of contemporary analysis methods essential? andIf the conventional analysis methods are used, what are the margins of error? Background: The Conventional Methods The standard models of horizontal-well-test analysis have been developed mostly during the 1980's.1-4,8,9 Despite the differences in the development of these models, the basic assumptions and the final solutions are similar. Fig. 1 is a sketch of the horizontal well-reservoir system considered in the pressure-transient-response models. A horizontal well of length Lh is assumed to be located in an infinite slab reservoir of thickness h. The elevation of the horizontal well from the bottom boundary of the formation (well eccentricity) is denoted by zw. The top and bottom reservoir boundaries are usually assumed to be impermeable, although some models consider constant-pressure boundaries.14,15 Before discussing the characteristic features of the conventional horizontal-well transient-pressure-response models, we must first define the dimensionless variables to be used in our discussion. We define the dimensionless pressure, time, and distance in the conventional manner except that we use the horizontal-well half-length, Lh/2, as the reference length in the system. These variables are defined, respectively, by the following expressions.Equation 1Equation 2Equation 3Equation 4 In Eqs. 1 through 3, k=the harmonic average of the principal permeabilities that are assumed to be in the directions of the coordinate axes (). We also define the dimensionless horizontal-well length, wellbore radius, and well eccentricity (distance from the bottom boundary of the formation) as follows.Equation 5Equation 6Equation 7 In Eq. 6, rw, eq=the equivalent radius of the horizontal well in an anisotropic reservoir.26

Improving Proppant Placement Success in Horizontal Wells in Layered Reservoirs in the Sultanate of Oman

2021 ◽  
Author(s):  
Andrew Boucher ◽  
Josef Shaoul ◽  
Inna Tkachuk ◽  
Mohammed Rashdi ◽  
Khalfan Bahri ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Complex Geometry ◽  
Horizontal Wells ◽  
Vertical Position ◽  
Sultanate Of Oman ◽  
Vertical Wells ◽  
Multiple Fractures ◽  
Initiation Point ◽  
Interval Selection ◽  
Geological Units

Abstract A gas condensate field in the Sultanate of Oman has been developed since 1999 with vertical wells, with multiple fractures targeting different geological units. There were always issues with premature screenouts, especially when 16/30 or 12/20 proppant were used. The problems placing proppant were mainly in the upper two units, which have the lowest permeability and the most heterogeneous lithology, with alternating sand and shaly layers between the thick competent heterolith layers. Since 2015, a horizontal well pilot has been under way to determine if horizontal wells could be used for infill drilling, focusing on the least depleted units at the top of the reservoir. The horizontal wells have been plagued with problems of high fracturing pressures, low injectivity and premature screenouts. This paper describes a comprehensive analysis performed to understand the reasons for these difficulties and to determine how to improve the perforation interval selection criteria and treatment approach to minimize these problems in future horizontal wells. The method for improving the success rate of propped fracturing was based on analyzing all treatments performed in the first seven horizontal wells, and categorizing their proppant placement behavior into one of three categories (easy, difficult, impossible) based on injectivity, net pressure trend, proppant pumped and screenout occurrence. The stages in all three categories were then compared with relevant parameters, until a relationship was found that could explain both the successful and unsuccessful treatments. Treatments from offset vertical wells performed in the same geological units were re-analyzed, and used to better understand the behavior seen in the horizontal wells. The first observation was that proppant placement challenges and associated fracturing behavior were also seen in vertical wells in the two uppermost units, although to a much lesser extent. A strong correlation was found in the horizontal well fractures between the problems and the location of the perforated interval vertically within this heterogeneous reservoir. In order to place proppant successfully, it was necessary to initiate the fracture in a clean sand layer with sufficient vertical distance (TVT) to the heterolith (barrier) layers above and below the initiation point. The thickness of the heterolith layers was also important. Without sufficient "room" to grow vertically from where it initiates, the fracture appears to generate complex geometry, including horizontal fracture components that result in high fracturing pressures, large tortuosity friction, limited height growth and even poroelastic stress increase. This study has resulted in a better understanding of mechanisms that can make hydraulic fracturing more difficult in a horizontal well than a vertical well in a laminated heterogeneous low permeability reservoir. The guidelines given on how to select perforated intervals based on vertical position in the reservoir, rather than their position along the horizontal well, is a different approach than what is commonly used for horizontal well perforation interval selection.

scholarly journals Mathematical description of a bounded oil reservoir with a horizontal well

2021 ◽  
Vol 2 (1) ◽  
pp. 67-76
Author(s):  
T. N. Nzomo ◽  
S. E Adewole ◽  
K. O Awuor ◽  
D. O. Oyoo
Keyword(s):  
Pressure Distribution ◽  
Effective Permeability ◽  
Horizontal Well ◽  
Horizontal Wells ◽  
Oil Reservoir ◽  
Vertical Wells ◽  
Anisotropic Permeability ◽  
Time Approximation ◽  
Reservoir Geometry ◽  
Short Time

Horizontal wells are more productive compared to vertical wells if their performance is optimized. For a completely bounded oil reservoir, immediately the well is put into production, the boundaries of the oil reservoir have no effect on the flow. The pressure distribution thus can be approximated with this into consideration. When the flow reaches either the vertical or the horizontal boundaries of the reservoir, the effect of the boundaries can be factored into the pressure distribution approximation. In this paper we consider the above cases and present a detailed mathematical model that can be used for short time approximation of the pressure distribution for a horizontal well with sealed boundaries. The models are developed using appropriate Green’s and source functions. In all the models developed the effect of the oil reservoir boundaries as well as the oil reservoir parameters determine the flow period experienced. In particular, the effective permeability relative to horizontal anisotropic permeability, the width and length of the reservoir influence the pressure response. The models developed can be used to approximate and analyze the pressure distribution for horizontal wells during a short time of production. The models presented show that the dimensionless pressure distribution is affected by the oil reservoir geometry and the respective directional permeabilities.

Evaluating the Performance of Horizontal Multi-Frac Wells in a Depleted Gas Condensate Reservoir in Sultanate of Oman

2022 ◽  
Author(s):  
Josef R. Shaoul ◽  
Jason Park ◽  
Andrew Boucher ◽  
Inna Tkachuk ◽  
Cornelis Veeken ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Gas Condensate ◽  
Integrated Analysis ◽  
Single Fracture ◽  
Reservoir Pressure ◽  
Well Test ◽  
Vertical Wells ◽  
Fracture Conductivity ◽  
Half Length

Abstract The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020. The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity. Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel. Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.

Successful Unlock for Non-Continuous Sand of Tight Gas Reservoir using Horizontal Wells

2021 ◽  
Author(s):  
Raed Mohamed Elmohammady ◽  
Mostafa Mahrous Ali ◽  
Hassan Elsayed Salem
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Western Desert ◽  
Tight Gas ◽  
Vertical Wells ◽  
Gas Reservoir ◽  
Horizontal Section ◽  
Reservoir Permeability ◽  
Wide Range ◽  
Tight Gas Reservoir

Abstract Reservoir development in Safa Formation requires a lot of vertical wells in order to exploit the gas reserve in the formation which means high cost is needed because the heterogeneity in the formation is noticed due to sandstone is pinched out in different locations of the reservoir. So, vertical well may be sweep from limited area of the reservoir that make safa formation has less priority for new activities. Form all of that the plan was drilling horizontal wells with long horizontal section to recover great volume of gas from reservoir. In addition to reduction in number of drilling vertical wells in the reservoir. In contrast, the major constrains is the small thickness of reservoir that make drilling horizontal section is very difficult. The main characteristics of safa formation is non continuous sandstone in the whole reservoir with great heterogeneity that not controlled by any points in the reservoir for the distribution of sandstone. In addition, there are a lot of locations in safa formation that include lean intervals which have kaolinite, elite that are not capable for produce from sand. In other hand, there is another constrains beside the discontinuity of sand production is the heterogeneity of permeability properties of reservoir that change in wide range across the reservoir with minimum range of 0.01 md and increase in some locations to reach 100 md. From all of the previous, it is a big challenge in drilling horizontal wells with long horizontal section in thin reservoir thickness in order to access the best reservoir permeability and optimize the number of drilling wells based on this concept. This paper will discuss case study of unlock and development long horizontal section in gas reservoir characterized by its tightness. The main goal of this horizontal well to recover ultimate gas reserve from safa formation by horizontal section reached to 2000 meter with a challenge because it is abnormal to drill this large horizontal section in western desert of Egypt in reservoir thickness range from 5 meter to 30 meter as prognosis from other offset wells in case of there is no pitchout of the sandstone. After Drilling of first horizontal well, the results were unexpected because the well penetrates a large horizontal section of sandstone in safa formation. This section reached to around 1750 meter with average reservoir permeability between 10 – 20 md and the reservoir porosity about 13% with good hydrocarbon saturation that changes along this section from 75% to 80%. So, this well put on production with very stable gas production rate 20 MMSCFD. In this paper will discuss in details the different challenge that faced to unlock this tight gas reservoir and will discuss the performance of horizontal well production. In this paper will discuss the first horizontal well in safa formation and the longest horizontal section in western desert of Egypt in tight gas formation that has a lot of challenges and risks are faced. After success the concept of horizontal well in heterogeneous reservoir, the next plan is the development of this reservoir using several horizontal wells to recover the ultimate recovery of gas from safa formation.

An Analytical Study of Interference in Composite Reservoirs

1985 ◽  
Vol 25 (02) ◽  
pp. 281-290 ◽  
Author(s):  
Abdurrahman Satman
Keyword(s):  
Pressure Drop ◽  
Composite System ◽  
Pressure Response ◽  
Oil Field ◽  
Observation Well ◽  
Wellbore Storage ◽  
Interference Test ◽  
Interference Tests ◽  
Inner Region ◽  
Observation Wells

Satman, Abdurrahman; SPE; Technical U. of Istanbul Abstract This paper discusses the interference test in composite reservoirs. The composite model considers all important parameters of interest: the hydraulic diffusivity, the mobility ratio, the distance to the radial discontinuity, the distance between wells, the wellbore storage, and skin effect at the active well. Type curves expressed as a function of proper combinations of these parameters are presented. Introduction Interference tests are widely used to estimate the reservoir properties. An interference test is a multiwell test that requires at least one active well, either a producer or injector, and at least one observation well. During the test, pressure effects caused by the active well are measured at the shut-in observation wells. Basic techniques for analyzing interference tests in uniform systems are discussed in Ref. 1. Usually, type-curve matching is the preferred technique for analyzing the pressure data from the test. Early interference test studies assumed that the storage capacity of the active well and the skin region around the sandface have a negligible effect on the observation well response. Recently, investigators have focused on wellbore storage and skin effects. Tongpenyai and Raghavan presented a new solution for analyzing the pressure response at the presented a new solution for analyzing the pressure response at the observation well, which took into account the effects of wellbore storage and skin at both the active and the observation wells. They produced type curves expressed as a function of exp(2S) products, the ( / ) ratios, and ( / ) to correlate the pressure response at the observation well. Composite systems are encountered in a wide variety of reservoir situations. In a composite system, there is a circular inner region with fluid and rock properties different from those in the outer region. Such a system can occur in hydrocarbon reservoirs and geothermal reservoirs. The injection of fluids during EOR processes can cause the development of fluid banks around the injection wells. This would be true in the case of a in-situ combustion or a steamflood. In a geothermal reservoir, pressure reduction in the vicinity of the well may cause the phase boundaries. A producing well completed in the center of a circular hot zone surrounded by producing well completed in the center of a circular hot zone surrounded by a concentric cooler water region is also a composite system. During the early to late 1960's, there was great interest in the composite reservoir flow problem. Hurst discussed the "sands in series" problem. He presented the formulas to describe the pressure behavior of problem. He presented the formulas to describe the pressure behavior of the unsteady-state flow phenomenon for fluid movement through two sands in series in a radial configuration, with each sand of different permeability. Mortada studied the interference pressure drop for oil fields located in a nonuniform extensive aquifer comprising two regions of different properties. He presented an expression for the interference pressure drop properties. He presented an expression for the interference pressure drop in an oil field resulting from a constant rate of water influx in another oil field. Loucks and Guerrero presented a qualitative discussion of pressure drop characteristics in composite reservoirs. Ramey and Rowan and pressure drop characteristics in composite reservoirs. Ramey and Rowan and Clegg developed approximate solutions. Refs. 11 through 13 also discuss composite reservoir systems and present either analytical or numerical solutions. Composite system model solutions have been used to determine some critical parameters during the application of EOR processes. The formation of a fluid bank around the injection well makes the reservoir a composite system. Van Poollen and Kazemi discussed how to determine the mean distance to the radial discontinuity in an in-situ combustion project. Refs. 16 and 17 discuss the effect of radial discontinuity in interpretation of pressure falloff tests in reservoirs with fluid banks. Sosa et al. examined the effect of relative permeability and mobility ratio on falloff behavior in reservoirs with water banks. The presence of different temperature zones in nonisothermal reservoirs may resemble permeability boundaries during well testing. Mangold et al. presented a numerical study of a thermal discontinuity in well test analysis. Their results indicated that nonisothermal influence could be detected and accounted for by tests of sufficient duration with suitably placed observation wells. Horne et al. indicated the possibility of determining compressibility and permeability contrasts across the phase boundaries in geothermal reservoirs. The most recent study of well test analysis in composite reservoirs was by Eggenschwiler, Satman et al. Their studies presented a very general composite system model. The problem was solved analytically by using the Laplace transformation with numerical inversion. The solution concerned the transient flow of a slightly compressible fluid in a porous medium during injection or falloff for a single well confined in concentric regions of differing mobilities and hydraulic diffusivities. The system assumed both wellbore storage and a skin effect. Their results indicated that a pseudosteady-state pressure response exists in the transition region between the inner region and outer region semilog straight lines. This response is drawn on a Cartesian vs. plot, the slope of which is used to estimate the bulk volume of the inner region. SPEJ p. 281

scholarly journals Study of the horizontal sidetracking efficiency using hydrodynamic modeling (on the example of a Kazakhstani field)

2022 ◽  
Vol 320 (1) ◽  
pp. 42-50
Author(s):  
K.A. Soltanbekova ◽  
◽  
B.K. Assilbekov ◽  
A.B. Zolotukhin ◽  
◽  
...  
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Vertical Wells ◽  
Optimal Length ◽  
Pressure Losses ◽  
Rate Versus ◽  
Horizontal Wellbore ◽  
Effective Development ◽  
Complex Architecture ◽  
Economic Criteria

One of the modern approaches for the effective development of small deposits is the construction and operation of wells with a complex architecture: horizontal wells (HW), sidetracks (BS, BGS), multilateral wells (MLW). Sidetracking makes it possible to reanimate an old well that is in an emergency state or inactivity for technological reasons, by opening layers that have not been previously developed, bypassing contamination zones, or watering the formation. This study examines the possibility of using horizontal sidetracks in the operating wells of the field of the Zhetybai group. To select the optimal length of the horizontal sidetrack of the wells, graphs of the dependences of the change in flow rate versus length of the horizontal well were built, taking into account the pressure losses due to friction. It can be seen from the dependence of NPV versus length of the horizontal wellbore that the maximum NPV is achieved with a horizontal wellbore length of 100 m. A further increase in the length of the horizontal wellbore leads to a decrease in NPV. This is due, firstly, to a decrease in oil prices, and secondly, interference of wells, a small number of residual reserves, and a small oil-bearing area. As a result of a comparison of technical and economic criteria, the optimal length of a horizontal wellbore is from 100-300 meters. Comparison of the flow rates of vertical wells and wells with horizontal sidetracks showed a clear advantage over the latter in all respects.

scholarly journals Inferring interwell connectivity in a reservoir from bottomhole pressure fluctuations of hydraulically fractured vertical wells, horizontal wells, and mixed wellbore conditions

2020 ◽  
Vol 10 ◽  
pp. 20-40
Author(s):  
Dinh Viet Anh ◽  
Djebbar Tiab
Keyword(s):  
Regression Analysis ◽  
Horizontal Well ◽  
Linear Regression Analysis ◽  
Pressure Fluctuations ◽  
Horizontal Wells ◽  
Multivariate Linear Regression Analysis ◽  
High Permeability ◽  
Vertical Wells ◽  
Interwell Connectivity ◽  
Bottomhole Pressure

A technique using interwell connectivity is proposed to characterise complex reservoir systems and provide highly detailed information about permeability trends, channels, and barriers in a reservoir. The technique, which uses constrained multivariate linear regression analysis and pseudosteady state solutions of pressure distribution in a closed system, requires a system of signal (or active) wells and response (or observation) wells. Signal wells and response wells can be either producers or injectors. The response well can also be either flowing or shut in. In this study, for consistency, waterflood systems are used where the signal wells are injectors, and the response wells are producers. Different borehole conditions, such as hydraulically fractured vertical wells, horizontal wells, and mixed borehole conditions, are considered in this paper. Multivariate linear regression analysis was used to determine interwell connectivity coefficients from bottomhole pressure data. Pseudosteady state solutions for a vertical well, a well with fully penetrating vertical fractures, and a horizontal well in a closed rectangular reservoir were used to calculate the relative interwell permeability. The results were then used to obtain information on reservoir anisotropy, high-permeability channels, and transmissibility barriers. The cases of hydraulically fractured wells with different fracture half-lengths, horizontal wells with different lateral section lengths, and different lateral directions are also considered. Different synthetic reservoir simulation models are analysed, including homogeneous reservoirs, anisotropic reservoirs, high-permeability-channel reservoirs, partially sealing barriers, and sealing barriers.The main conclusions drawn from this study include: (a) The interwell connectivity determination technique using bottomhole pressure fluctuations can be applied to waterflooded reservoirs that are being depleted by a combination of wells (e.g. hydraulically fractured vertical wells and horizontal wells); (b) Wellbore conditions at the observations wells do not affect interwell connectivity results; and (c) The complex pressure distribution caused by a horizontal well or a hydraulically fractured vertical well can be diagnosed using the pseudosteady state solution and, thus, its connectivity with other wells can be interpreted.

Sign in / Sign up

Export Citation Format

Share Document