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.

scholarly journals Parameter Optimization of Segmental Multicluster Fractured Horizontal Wells in Extremely Rich Gas Condensate Shale Reservoirs

2021 ◽  
Vol 9 ◽  
Author(s):  
Wei Zhipeng ◽  
Wang Jinwei ◽  
Liu Rumin ◽  
Wang Tao ◽  
Han Guannan
Keyword(s):  
Shale Gas ◽  
Horizontal Well ◽  
Production Capacity ◽  
Horizontal Wells ◽  
Distribution Patterns ◽  
Gas Condensate ◽  
Fracture Permeability ◽  
Mesh Density ◽  
Fractured Horizontal Wells ◽  
Half Length

For economic and efficient development of extremely high-condensate shale gas reservoirs, a numerical model of segmental multicluster fractured horizontal well was established considering the effect of condensate and desorption, and the optimization of fracturing segments, fracturing clusters, half-length of main fracture, fracture permeability, fracture mesh density, and fracture distribution patterns were studied. It is indicated that the horizontal well whose design length is 2,700 m performs best when it has 43 fracturing segments with three clusters in each segment and the fracture permeability is 300 mD. The production capacity of horizontal wells is positively linearly correlated with the half-length of fractures. Increasing fracture half-length would be an effective way to produce condensate oil near wellbore. An effective fractured area can be constructed to remarkably improve productivity when the half-length of the fracture is 50 m and the number of secondary fractures is four in each segment. On the basis of reasonable fracture parameters, the staggered type distribution pattern is beneficial to the efficient development of shale gas-condensate reservoirs because of its large reconstruction volume, far pressure wave, small fracture interference, and small precipitation range of condensate.

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.

Parameters Optimization of Fractures with One for Injection and Two Others for Production of Horizontal Wells Fracturing on Offshore Oilfields

2014 ◽  
Vol 962-965 ◽  
pp. 489-493
Author(s):  
Zhi Qiang Li ◽  
Yong Quan Hu ◽  
Wen Jiang Xu ◽  
Jin Zhou Zhao ◽  
Jian Zhong Liu ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Oil Production ◽  
Horizontal Wells ◽  
Simulation Method ◽  
Parameters Optimization ◽  
Development Mode ◽  
Fracture Conductivity ◽  
Fracture Length ◽  
Fractured Horizontal Well ◽  
Production Research

This article presents a new exploitation method based on the same fractured horizontal well with fractures for injection or production on offshore low permeability oilfields for the purpose of adapting to their practical situations and characteristics, which means fractures close to the toe of horizontal well used for injecting water and fractures near the heel of horizontal well used for producing oil. According to proposed development mode of fracturing, relevant physical model is established, Then reservoir numerical simulation method has been applied to study the effect of arrangement pattern of injection and production fractures, fracture conductivity, fracture length on oil production. Research indicates cumulative oil production is much higher by employing the middle fracture for injecting water compared with using the remote one, suggesting that the middle fracture adopted for injecting water, and hydraulic fracture length and conductivity have been optimized. The proposed development pattern of a staged fracturing for horizontal wells with some fractures applied for injecting water and others for production based on the same horizontal well provides new thoughts for offshore oilfields exploitation.

Comparison of Fractured-Horizontal-Well Performance in Tight Sand and Shale Reservoirs

2011 ◽  
Vol 14 (02) ◽  
pp. 248-259 ◽  
Author(s):  
E.. Ozkan ◽  
M Brown ◽  
R.. Raghavan ◽  
H.. Kazemi
Keyword(s):  
Hydraulic Fracture ◽  
Horizontal Well ◽  
Flow Model ◽  
Horizontal Wells ◽  
Natural Fracture ◽  
Well Performance ◽  
Fracture Conductivity ◽  
Fractured Horizontal Well ◽  
Shale Reservoirs ◽  
Fractured Horizontal Wells

Summary This paper presents a discussion of fractured-horizontal-well performance in millidarcy permeability (conventional) and micro- to nanodarcy permeability (unconventional) reservoirs. It provides interpretations of the reasons to fracture horizontal wells in both types of formations. The objective of the paper is to highlight the special productivity features of unconventional shale reservoirs. By using a trilinear-flow model, it is shown that the drainage volume of a multiple-fractured horizontal well in a shale reservoir is limited to the inner reservoir between the fractures. Unlike conventional reservoirs, high reservoir permeability and high hydraulic-fracture conductivity may not warrant favorable productivity in shale reservoirs. An efficient way to improve the productivity of ultratight shale formations is to increase the density of natural fractures. High natural-fracture conductivities may not necessarily contribute to productivity either. Decreasing hydraulic-fracture spacing increases the productivity of the well, but the incremental production gain for each additional hydraulic fracture decreases. The trilinear-flow model presented in this work and the information derived from it should help the design and performance prediction of multiple-fractured horizontal wells in shale reservoirs.

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.

Well Test Analysis of Horizontal wells in Gas-Condensate Reservoirs

2004 ◽  
Author(s):  
Abdolnabi Hashemi ◽  
Laurent M. Nicolas ◽  
Alain C. Gringarten
Keyword(s):  
Horizontal Wells ◽  
Gas Condensate ◽  
Well Test ◽  
Well Test Analysis ◽  
Test Analysis ◽  
Gas Condensate Reservoirs

Optimizing the Number of Fractures in a Horizontal Well

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1364-1377 ◽  
Author(s):  
Vyacheslav Guk ◽  
Mikhail Tuzovskiy ◽  
Don Wolcott ◽  
Joe Mach
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Optimal Number ◽  
Hydraulic Fractures ◽  
Single Fracture ◽  
Multiple Fracture ◽  
Multiple Fractures ◽  
Type Curves ◽  
Fracture Width ◽  
Technical Potential

Summary Horizontal wells with multiple hydraulic fractures have become a standard completion for the development of tight oil and gas reservoirs. Successful optimization of multiple-fracture design on horizontal wells began empirically in the Barnett Shale in the late 1990s (Steward 2013; Gertner 2013). More recently, research has focused on further improving fracturing performance by developing a model-derived optimum. Some researchers have focused on an economic optimum on the basis of multiple runs of an analytical or numerical model (Zhang et al. 2012; Saputelli et al. 2014). With such an approach, a new set of model runs is necessary to optimize the design each time the input parameters change significantly. Running multiple simulations for every optimization case might not always be practical. An alternative approach is to develop well-performance curves with dimensionless variables on the basis of the performance model. Such an approach was the basis for unified fracture design (UFD) for a single fracture in a vertical well (Economides et al. 2002). However, a similar systemized method to calculate the optimum for a horizontal well with multiple hydraulic fractures was missing. The objective of this study was to develop a rigorous and unified dimensionless optimization technique with type curves for the case of multiple transverse fractures in a horizontal well—an extension of UFD. The mathematical problem was solved in dimensionless variables. Multiple fractures include the proppant number (NP), penetration ratio (Ix), dimensionless conductivity (CfD), and aspect ratio (yeD) for each fracture, which is inversely proportional to the number of fractures. The direct boundary element (DBE) method was used to generate the dimensionless productivity index (JD) for a given range of these parameters (28,000 runs) for the pseudosteady-state case. Finally, total well JD was plotted as a function of the number of fractures for various NP. The effect of minimum fracture width was studied, and the optimization curves were adjusted for three cases of minimum fracture width. The provided dimensionless type curves can be used to identify the optimized number of fractures and their geometry for a given set of parameters, without running a more complicated numerical model multiple times. First, the proppant mass (and hence, NP) used for the fracture design can be selected on the basis of economic or other considerations. For this purpose, a relationship between total JD and NP, which accounts for the minimum fracture width requirement, was provided. Then, the optimal number of fractures can be calculated for a given NP using the generated type curves with minimum width constraints. The following observations were made during the study on the basis of the performed runs: For a given volume or proppant, NP, total JD for multiple fractures increases to an asymptote as the number of fractures increases. This asymptote represents a technical potential for multiple fractures and for high proppant numbers (NP≥100), with a technical potential of 3πNP. Below this asymptote, the more fractures that are created for a fixed NP, the larger the JD. In practice, minimum fracture width constrains the fracture geometry, and therefore maximum JD. For the case when 20/40 sand is used for multiple hydraulic fracturing of a 0.01-md formation with square total area, the optimal number of factures is approximately NP25. Application of horizontal drilling technology with multiple fractures assumes the availability of high proppant numbers. It was shown mathematically that the alternative low proppant numbers (NP≤20 for the previous case) are impractical for multiple fractures, because total JD cannot be significantly higher than JD for an optimized single fracture in the same area. This means that low formation permeability and/or high proppant volumes are needed for multiple fracture treatments.

scholarly journals Productivity Evaluation for Long Horizontal Well Test in Deep-Water Faulted Sandstone Reservoir

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-10
Author(s):  
Zhiwang Yuan ◽  
Li Yang ◽  
Yingchun Zhang ◽  
Rui Duan ◽  
Xu Zhang ◽  
...  
Keyword(s):  
Steady State ◽  
Deep Water ◽  
Horizontal Well ◽  
Evaluation Method ◽  
Horizontal Wells ◽  
Productivity Index ◽  
Test Time ◽  
Well Test ◽  
Well Productivity ◽  
Sandstone Reservoir

For deep-water faulted sandstone reservoirs, the general practice is to design long horizontal wells improving well productivity. During the project implementation stage, well tests are performed on all drilled wells to evaluate well productivity accurately. Furthermore, multisize chokes are often utilized in a shorten test time for loosen formation, high test cost, and high well productivity. Nevertheless, the conventional productivity evaluation approach cannot accurately evaluate the well test productivity and has difficulty in determining the underneath pattern. As a result, the objective of this paper is to determine a productivity evaluation method for multisize chokes long horizontal well test in deep-water faulted sandstone reservoir. This approach introduces a productivity model for long horizontal wells in faulted sandstone reservoir. It also includes the determination of steady-state test time and the productivity evaluation method for multisize chokes. In this paper, the EGINA Oilfield, a deep-water faulted sandstone reservoir, located in West Africa was chosen as the research target. Based on Renard and Dupuy’s steady-state equation, the relationship between the productivity index per meter and the length of horizontal section was derived. Consequently, this relationship is used to determine the productivity pattern for long horizontal wells with the same geological features, which can provide more accurate productivity evaluations for tested wells and forecast the well productivity for untested wells. After implementing this approach on the EGINA Oilfield, the determined relationship is capable to accurately evaluate the test productivity for long horizontal wells in reservoirs with similar characteristics and assist in examination and treatment for horizontal wells with abnormal productivity.

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