Maximizing Condensate Recovery With Proven Cost Simulation for a Giant UAE Field: Base Study to Estimate Productivity between Horizontal and Vertical Wells

2021 ◽  
Author(s):  
Maxim Sudarev ◽  
Mariam Al Hosani ◽  
Ahmed Mohamed Al Bairaq ◽  
Ihab Nabil Mohamed ◽  
Zainah Salem Al Agbari ◽  
...  
Keyword(s):  
Horizontal Wells ◽  
Gas Production ◽  
Vertical Wells ◽  
Hydrodynamic Simulation ◽  
Field Assessment ◽  
Base Study ◽  
Horizontal And Vertical Wells ◽  
High Production ◽  
Production Demand

Abstract Implementing the horizontalization scheme was developed for number of wells in order to increase the Gas and Condensate production, which will achieve sustainable and profitable Gas Supply. It worth to highlight that most of these wells are being subjected to N2 and lean gas breakthroughs. By adopting a comparison methodology, the horizontal wells showed better performance in terms of HC production and CGR performance. The number of breakthrough in horizontal wells is less or delayed in term of time. High production demand was promoting this project to take place, where the current situation was not supporting due to N2 and lean gas breakthrough, which is affecting the quality of the gas sales. It was challenging to balance between high production demand, N2, and lean gas breakthrough. Initially, optimizing the production allowable was considered to maximize the production from high CGR wells and minimize the production from low CGR wells. The sidetrack scheme is important to penetrate the un-swept area and to maintain the geometry/distances between wells to prevent early breakthrough and minimize the interference. All results from surveillance and hydrodynamic simulation were integrated for final field assessment impact. This work has resulted in positive expected outcome with few millions additional condensate recovery and extended gas production plateau. According the outcomes analysis the implementation plan was designed.

Plug and Abandonment Environment in British Columbia

2019 ◽  
Author(s):  
Majid Bizhani ◽  
Élizabeth Trudel ◽  
Ian Frigaard
Keyword(s):  
British Columbia ◽  
Fractured Reservoirs ◽  
Horizontal Wells ◽  
Gas Production ◽  
Vertical Wells ◽  
Gas Industry ◽  
Testing Procedures ◽  
The Past ◽  
Production Wells ◽  
Well Abandonment

Abstract British Columbia (BC) has a significant oil & gas industry, with approximately 25,000 wells drilled in the province since the early 1900s. In the past few decades, the industry has changed from a balanced oil & gas production to activities dominated by unconventional gas production which is recovered by hydraulic fracturing. Concurrently, since 2000 there has been a shift from isolated vertical wells to pad-drilled horizontal wells. The older well stock at end-of-life combines with horizontal production wells and fractured reservoirs, the consequence of which is a growing wave of abandonment in BC, building over the next decade. This paper reviews the existing data on BC wells, as it is relevant to well abandonment operations. This includes the well architectures, trajectories, depths, testing procedures, etc.

Domestic rotary steerable systems development potential for drilling horizontal wells

2020 ◽  
pp. 74-80
Author(s):  
V. V. Saltykov ◽  
Yu. S. Makovsky ◽  
M. M. Mansurova
Keyword(s):  
Horizontal Wells ◽  
Systems Development ◽  
Oil Field ◽  
High Tech ◽  
Technological Solution ◽  
Deviation Angle ◽  
Vertical Wells ◽  
Special Equipment ◽  
The Past

A complex of special equipment is required for the construction of high-tech wells. The basis of modern time efficient, precise and safe drilling is rotary steerable systems (RSS). For the past five years, rotary steerable systems have been using in Russia as a technical and technological solution to reduce accidents and to improve the quality of well construction with large vertical deviations of the extended drilling radius. These systems allow drilling to be oriented along the entire length of the well. Rotary steerable systems allows drilling both perfectly vertical wells with a deviation angle of not more than 0,2°, and horizontal wells more than 2 000 metres long. Implementation of rotary steerable systems allows building wells with extremely extended reach and conducting wells in 1–2 metres thick reservoirs with precision. In 2016, OktoGeo LLC carried out pilot well program with APS Technology's 172 mm RSS (with power section) at an oil field in the territory of KhantyMansiysk Autonomous Okrug — Ugra. All the rotary steerable system positioning programs were completed based on the results of that work and results of drilling 2 205 metres long directional well.

Methane Production Strategies for Oceanic Gas Hydrate Reservoirs

2019 ◽  
Author(s):  
Neelam Choudhary ◽  
Jyoti Phirani
Keyword(s):  
Gas Hydrate ◽  
Fossil Fuels ◽  
Gas Production ◽  
Warm Water ◽  
Vertical Wells ◽  
Methane Gas ◽  
Potential Source ◽  
Horizontal And Vertical Wells ◽  
The Impact ◽  
Hydrate Reservoirs

Abstract Gas hydrates can be an efficient replacement for the conventional fossil fuels, as the large amount of methane gas is trapped in the gas hydrate reservoirs that can be used as a potential source of energy. In this study, we investigate the impact of a combination of horizontal and vertical wells on the gas production from oceanic Class-2, unconfined gas hydrate reservoirs. An In-house multicomponent, multiphase, thermal, 3-D finite volume simulator is used. Different locations of horizontal and vertical wells as warm water injectors and methane gas producers are investigated. For unconfined reservoirs, depressurization is found to be ineffective with horizontal and vertical wells. Horizontal warm water injectors are more effective for gas production. The gas production increases from 22% of original gas in place (OIGP) when vertical injector is used to 48% of OGIP when horizontal injector is used.

scholarly journals Research of inflow control devices for estimation of application in intellectual well

2021 ◽  
pp. 201-209
Author(s):  
R. A. Ismakov ◽  
◽  
E. V. Denisova ◽  
S. P. Sidorov ◽  
M. A. Chernikova ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Horizontal Wells ◽  
Control Device ◽  
Gas Production ◽  
Vertical Wells ◽  
Oil And Gas Production ◽  
Urgent Task ◽  
Measurement Devices ◽  
Control Devices ◽  
Inflow Control Device

Ensuring the completeness of oil and gas production from the subsoil by using modern techniques and technologies for controlling the inflow into the well is an urgent task, especially for wells with long horizontal ends. Inflow control devices (ICD), used in conjunction with packers and downhole measurement devices, are part of such systems, covered by the concept of «smart well». In general, such systems make it possible to control the inflow (flow rate) in individual intervals of horizontal wells or in vertical wells of multilayer fields while operating simultaneously in order to optimize production without additional downhole operations in real time. Keywords: inflow control device; horizontal well; intelligent well.

Evaluation of Inflow Performance of Multiple Horizontal Wells in Closed Systems

1999 ◽  
Vol 122 (1) ◽  
pp. 8-13 ◽  
Author(s):  
Suwan Umnuayponwiwat ◽  
Erdal Ozkan
Keyword(s):  
Horizontal Well ◽  
Transient Flow ◽  
Horizontal Wells ◽  
Vertical Wells ◽  
Well Pattern ◽  
Horizontal And Vertical Wells ◽  
Closed Systems ◽  
Inflow Performance

This work presents a model to investigate the inflow performance relationships (IPR) of horizontal and vertical wells in a multi-well pattern. The model can be used to compute the overall and individual well performances. It is shown that stabilized IPRs may not be sufficient for the evaluation of horizontal well performances due to prolonged transient flow periods. The results presented in this paper clearly indicate that inflow performance of wells in a multi-well pattern is a dynamic concept; and, especially in the prediction of future performances, dynamic rather than static IPR models should be used. [S0195-0738(00)00801-3]

Analysis of Data From the Barnett Shale Using Conventional Statistical and Virtual Intelligence Techniques

2011 ◽  
Vol 14 (05) ◽  
pp. 544-556 ◽  
Author(s):  
Obadare O. Awoleke ◽  
Robert H. Lane
Keyword(s):  
Neural Network ◽  
Horizontal Wells ◽  
Recovery Factor ◽  
Barnett Shale ◽  
Production Data ◽  
Water Production ◽  
Vertical Wells ◽  
Self Organizing Maps ◽  
Data Set ◽  
Horizontal And Vertical Wells

Summary A Barnett shale water-production data set from approximately 11,000 completions was analyzed using conventional statistical techniques. Additionally, a water/hydrocarbon ratio and first-derivative diagnostic-plot technique developed elsewhere for conventional reservoirs was extended to analyze Barnett shale water-production mechanisms. To determine hidden structure in well and production data, self-organizing maps and the k-means algorithm were used to identify clusters in data. A competitive-learning-based network was used to predict the potential for continuous water production from a new well, and a feed-forward neural network was used to predict average water production for wells drilled in Denton and Parker Counties, Texas, of the Barnett shale. Using conventional techniques, we concluded that for wells of the same completion type, location is more important than time of completion or hydraulic-fracturing strategy. Liquid loading has potential to affect vertical more than horizontal wells. Different features were observed in the spreadsheet diagnostic plots for wells in the Barnett shale, and we made a subjective interpretation of these features. We find that 15% of the horizontal and vertical wells drilled in Denton County have a load-water-recovery factor greater than unity. Also, 15 and 35% of the horizontal and vertical wells drilled, respectively, in Parker County have a load-recovery factor greater than unity.The use of both self-organizing maps and the k-means algorithm showed that the data set is divided into two main clusters. The physical properties of these clusters are unknown but interpreted to represent wells with high water throughput and those with low water throughput. Expected misclassification error for the competitive-learning-based tool was approximately 10% for a data set containing both vertical and horizontal wells. The average prediction error for the neural-network tool varied between 10 and 26%, depending on well type and location.Results from this work can be used to mitigate risk of water problems in new Barnett shale wells and predict water issues in other shale plays. Engineers are provided a tool to predict potential for water production in new wells. The method used to develop this tool can be used to solve similar challenges in new and existing shale plays.

Effect of Scaling Parameters on Waterflood Performance with Horizontal and Vertical Wells

2008 ◽  
Vol 22 (1) ◽  
pp. 402-409 ◽  
Author(s):  
Nanji J. Hadia ◽  
Lalit S. Chaudhari ◽  
Sushanta K. Mitra ◽  
Madhu Vinjamur ◽  
Raghuvir Singh
Keyword(s):  
Vertical Wells ◽  
Scaling Parameters ◽  
Horizontal And Vertical Wells

Characteristics of Dimensionless Pressure Gradients and Derivatives of Horizontal and Vertical Wells Completed within Inclined Sealing Faults

2021 ◽  
Author(s):  
A V Ogbamikhumi ◽  
E S Adewole
Keyword(s):  
Pressure Drop ◽  
Horizontal Well ◽  
Superposition Principle ◽  
Early Time ◽  
Pressure Gradients ◽  
Vertical Wells ◽  
Pressure Derivative ◽  
Vertical Well ◽  
Dimensionless Pressure ◽  
Horizontal And Vertical Wells

Abstract Dimensionless pressure gradients and dimensionless pressure derivatives characteristics are studied for horizontal and vertical wells completed within a pair of no-flow boundaries inclined at a general angle ‘θ’. Infinite-acting flow solution of each well is utilized. Image distances as a result of the inclinations are considered. The superposition principle is further utilized to calculate total pressure drop due to flow from both object and image wells. Characteristic dimensionless flow pressure gradients and pressure derivatives for the wells are finally determined. The number of images formed due to the inclination and dimensionless well design affect the dimensionless pressure gradients and their derivatives. For n images, shortly after very early time for each inclination, dimensionless pressure gradients of 1.151(N+1)/LD for the horizontal well and 1.151(N+1) for vertical well are observed. Dimensionless pressure derivative of (N+1)/2LD are observed for central and off-centered horizontal well locations, and (N+1)/2 for vertical well are observed. Central well locations do not affect horizontal well productivity for all the inclinations. The magnitudes of dimensionless pressure drop and dimensionless pressure derivatives are maximum at the farthest image distances, and are unaffected by well stand-off for the horizontal well.

An ESP Production Optimization Algorithm Applied to Unconventional Wells

2021 ◽  
Author(s):  
Fernando Bermudez ◽  
Noor Al Nahhas ◽  
Hafsa Yazdani ◽  
Michael LeTan ◽  
Mohammed Shono
Keyword(s):  
Gas Production ◽  
Oil Wells ◽  
Production Optimization ◽  
Operating Conditions ◽  
Tight Oil ◽  
Daily Production ◽  
Free Gas ◽  
Maximum Production ◽  
Electrical Submersible Pumps ◽  
High Production

Abstract The objectives and Scope is to evaluate the feasibility of a Production Maximization algorithm for ESPs on unconventional wells using projected operating conditions instead of current ones, which authors expect will be crucial in adjusting the well deliverability to optimum frequencies on the rapidly changing conditions of tight oil wells. Actual production data for an unconventional well was used, covering from the start of Natural Flow production up to 120 days afterwards. Simulating what the production would be if a VFD running on IMP Optimization algorithms had been installed, new values for well flowing pressures were calculated, daily production scenarios were evaluated, and recommended operating frequencies were plotted. Result, observations, and conclusions: A. Using the Intelligent Maximum Production (IMP) algorithm allows maximum production from tight oil wells during the initial high production stage, and the prevention of gas-locking at later stages when gas production increases. B. The adjustment of frequency at later stages for GOR wells is key to maintaining maximum production while controlling free gas at the intake when compared against controlling the surface choke. Novel/additive information: The use of Electrical Submersible Pumps for the production of unconventional wells paired with the use of a VFD and properly designed control algorithms allows faster recovery of investment by pumping maximum allowable daily rates while constraining detrimental conditions such as free gas at the intake.

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.

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