A Holistic Study on Performance Evaluation of Horizontal Wells and its Implications on Tight Spacing Drilling Strategy in Mauddud Reservoir

2021 ◽  
Author(s):  
Lakshi Konwar ◽  
Bader Alhammadi ◽  
Ebrahim Alawainati ◽  
Ajithkumar Panicker
Keyword(s):  
Performance Evaluation ◽  
Future Development ◽  
Horizontal Well ◽  
Horizontal Wells ◽  
Productivity Index ◽  
Water Production ◽  
Vertical Wells ◽  
Productivity Improvement ◽  
Well Productivity ◽  
Improvement Factor

Abstract The objective of this paper is to present the comparative results of comprehensive analysis of horizontal well productivity and completion performance with vertical wells drilled and completed within same time window in the Mauddud reservoir in the Bahrain Oil Field. The study also focuses on performance evaluation of horizontal wells drilled in different areas of the field. Key reservoir risks and uncertainties associated with horizontal wells are identified, and contingency and mitigation plans are devised to address them. Besides controlling gas production, the benefits of using cemented horizontal wells over vertical wells are highlighted based on performance of recently completed workovers and economic evaluation. Reservoir and well performance are analyzed using a variety of analytical techniques such as well productivity index (PI), productivity improvement factor (PIF), normalized productivity improvement factor (PIFn), well productivity coefficient (Cwp), in conjunction with a statistical distribution function to reflect the average and most likely values. In addition, average oil/gas/water production, cumulative production, reserves, and estimated ultimate recovery (EUR) are compared for both vertical and horizontal wells using decline curve analysis. Furthermore, economics are evaluated for tight spacing drilling with vertical wells, as well as horizontal cemented wells, to optimize future development of Mauddud reservoir. Based on the evaluation, it is inferred that the average horizontal well outperforms a vertical well in terms of production rate, PI, PIF, reserves, and EUR in the field except in waterflood areas. Based on average cumulative oil, reserves and EUR, and well productivity coefficient, overall performance of horizontal wells are better in the GI area in comparison their counterparts in the North/South areas of the Mauddud reservoir, where the dominant mechanism is strong water drive. High gas and water production in horizontal wells are attributed to open-hole completions of the wells and the possibility of poor cementing. A trial has been completed recently in a few horizontal wells using cased-hole cemented completion with selected perforations, resulting in improved oil rates and the drastic reduction of gas to oil ratio. Furthermore, two new cased-hole cemented horizontal wells are planned in 2021 as a trial. A detailed cost-benefit analysis using a net present value concept is performed, leading to a rethink of future development strategies with a mix of both vertical as well as horizontal wells in the GI area. Using the dimensionless correlations and distribution functions, the productivity and PIF of new horizontal wells to be drilled in any area can be predicted during early prognosis given the values of average reservoir permeability, well length, and fluid properties. This study can be used as a benchmark for the development of a thin oil column with a large and expanding gas cap under crestal gas injection using both vertical and horizontal wells.

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.

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.

A Semianalytical Model for Horizontal-Well Productivity With Pressure Drop Along the Wellbore

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1603-1614 ◽  
Author(s):  
Wanjing Luo ◽  
Changfu Tang ◽  
Yin Feng
Keyword(s):  
Reynolds Number ◽  
Fluid Flow ◽  
Pressure Drop ◽  
Horizontal Well ◽  
Horizontal Wells ◽  
Productivity Index ◽  
Type Curves ◽  
Penetration Ratio ◽  
New Type ◽  
The One

Summary This study aims to develop a semianalytical model to calculate the productivity index (PI) of a horizontal well with pressure drop along the wellbore. It has been indicated that by introducing novel definitions of horizontal-well permeability and conductivity, the equation of fluid flow along a horizontal well with pressure drop has the same form as the one for fluid flow in a varying-conductivity fracture. Thus, the varying-conductivity-fracture model and PI model can be used to obtain the PI of a horizontal well. Results indicate that the PI of a horizontal well depends on the interaction between horizontal-well conductivity, penetration ratio, and Reynolds number. New type curves of the penetration ratios with various combinations of parameters have been presented. A complete-penetration zone and a partial-penetration zone can be identified on the type curves. Based on the type curves, two examples have also been presented to illustrate the advantages of this work in optimizing parameters of horizontal wells.

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.

Estimating the Specific Productivity Index in Horizontal Wells From Distributed-Pressure Measurements Using an Adjoint-Based Minimization Algorithm

SPE Journal ◽  
2012 ◽  
Vol 17 (03) ◽  
pp. 742-751 ◽  
Author(s):  
F.. Farshbaf Zinati ◽  
J.D.. D. Jansen ◽  
S.M.. M. Luthi
Keyword(s):  
Horizontal Well ◽  
Adjoint Method ◽  
Horizontal Wells ◽  
Measurement Noise ◽  
Productivity Index ◽  
Specific Productivity ◽  
Inversion Method ◽  
Pressure Measurements ◽  
Sensor Resolution ◽  
Distributed Pressure

Summary Recent developments in the deployment of distributed-pressure-measurement devices in horizontal wells promise to lead to a new, low-cost, and reliable method of monitoring production and reservoir performance. Practical applicability of distributed-pressure sensing for quantitative-inflow detection will strongly depend on the specifications of the sensors, details of which were not publicly available at the time of publication. Therefore, we theoretically examined the possibility of identifying reservoir inflow from distributed-pressure measurements in the well. The wellbore and nearwellbore region were described by semianalytical steady-state models, and a gradient-based inversion method was applied to estimate the specific productivity index (SPI) as a function of along-well position. We employed the adjoint method to obtain the gradients, which resulted in a computationally efficient inversion scheme. With the aid of two numerical experiments (one of which was based on a real well and reservoir), we investigated the effects of well and reservoir parameters, sensor spacing, sensor resolution, and measurement noise on the quality of the inversion results. In both experiments, we generated synthetic measurements with the aid of a high-resolution reservoir-simulation model and used these to test the semianalytical inversion algorithm. In the first experiment, we considered a 2000-m horizontal well passing through two 300-m high-permeability streaks in a background with a permeability that was 10 times lower. The location of the streaks and the SPIs along the well were detected with fair accuracy using 20 unknown parameters (SPI values) and 20 pressure measurements. Decreasing the number of measurements resulted in a poorer detection of the streaks and their SPIs. The detection performance also decreased for increasing noise levels and deteriorated sensor resolution, though the negative effect of random measurement noise was cancelled out primarily by stacking multiple measurements. The detrimental effects of measurement noise and low sensor resolution were strongest in areas where the inflow was lowest (usually close to the toe). The second experiment concerned a high-rate near-horizontal well with slightly varying inclination that intersected a dipping package of formations with strongly variable permeabilities. Additionally, a satisfactory detection of SPIs was obtained even though the heterogeneities were no longer perpendicular to the well as in the first experiment. As a result of using the simple semianalytical forward model and the adjoint method, the inversions typically required less than 90 seconds on a standard laptop. This offered the opportunity to extend the algorithm to multiphase flow and dynamic applications (pressure-transient testing), while still maintaining sufficient computational speed to perform the inversion in real time.

scholarly journals A Modeling Study of the Productivity of Horizontal Wells in Hydrocarbon-Bearing Reservoirs: Effects of Fracturing Interference

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Lei Huang ◽  
Peijia Jiang ◽  
Xuyang Zhao ◽  
Liang Yang ◽  
Jiaying Lin ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Well ◽  
Finite Difference Methods ◽  
Horizontal Wells ◽  
Fracture Initiation ◽  
Design Parameters ◽  
Porous Media Flow ◽  
Propagation Mechanism ◽  
Well Productivity ◽  
Fracturing Process

Commercial production from hydrocarbon-bearing reservoirs with low permeability usually requires the use of horizontal well and hydraulic fracturing for the improvement of the fluid diffusivity in the matrix. The hydraulic fracturing process involves the injection of viscous fluid for fracture initiation and propagation, which alters the poroelastic behaviors in the formation and causes fracturing interference. Previous modeling studies usually focused on the effect of fracturing interference on the multicluster fracture geometry, while the related productivity of horizontal wells is not well studied. This study presents a modeling workflow that utilizes abundant field data including petrophysical, geomechanical, and hydraulic fracturing data. It is used for the quantification of fracturing interference and its correlation with horizontal well productivity. It involves finite element and finite difference methods in the numeralization of the fracture propagation mechanism and porous media flow problems. Planar multistage fractures and their resultant horizontal productivity are quantified through the modeling workflow. Results show that the smaller numbers of clusters per stage, closer stage spacings, and lower fracturing fluid injection rates facilitate even growth of fractures in clusters and stages and reduce fracturing interference. Fracturing modeling results are generally correlated with productivity modeling results, while scenarios with stronger fracturing interference and greater stimulation volume/area can still yield better productivity. This study establishes the quantitative correlation between fracturing interference and horizontal well productivity. It provides insights into the prediction of horizontal well productivity based on fracturing design parameters.

Productivity-Maximized Horizontal-Well Design With Multiple Acute-Angle Transverse Fractures

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1539-1551 ◽  
Author(s):  
Nadav Sorek ◽  
Jose A. Moreno ◽  
Ryan N. Rice ◽  
Guofan Luo ◽  
Christine Ehlig-Economides
Keyword(s):  
Horizontal Well ◽  
Acute Angle ◽  
Productivity Index ◽  
Hydraulic Fractures ◽  
Flow Area ◽  
Well Productivity ◽  
Fracture Angle ◽  
Fracture Length ◽  
Stress Direction ◽  
Minimum Stress

Summary Hydraulic fractures propagate perpendicular to the horizontal-well axis whenever the drilling direction is parallel to the minimum-principal-stress direction. However, operators frequently drill horizontal wells parallel to lease boundaries, resulting in hydraulic-fracture vertical planes slanted at angles less than 90° from the well axis. The stimulated-rock-volume (SRV) dimensions are defined by fracture height, well length, and fracture length multiplied by the sine of the angle between fracture planes and the horizontal-well axis (fracture angle). The well productivity index (PI) under boundary-dominated flow (BDF) is given by the PI for one fully penetrating fracture multiplied by the number of fractures. An extension of the unified-fracture-design (UFD) approach for rectangular drainage areas enables determination of the unique number of fractures that will maximize well productivity under BDF conditions given the formation permeability, proppant mass, fracture angle, and well spacing. Fracture length and width vary depending on the fracture angle, but the total-propped-fracture volume remains constant. Because the likely reason for drilling at an angle to the minimum-stress direction is to better cover a lease area with north/south and east/west boundaries, the smallest fracture angle will be 45°, corresponding to northwest/southeast or northeast/southwest minimum-stress direction. This results in the need to lengthen fractures by at most 40% to preserve the SRV for a given horizontal-well length and spacing. For the same sufficiently large proppant mass, this will reduce fracture conductivity by the same factor. However, because the flow area has increased, the result will be greater well productivity. This study shows a simple strategy for designing wells to maximize productivity even when not drilled in the minimum-stress direction.

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