bluuebunny/crossref_metadata_2025_split huggingface dataset:
Selecting Optimum Completion Strategy – Examples from Saudi Arabia's Unconsolidated Unayzah Reservoir
Authors: Al-Anazi Hasan D. , Al-Qahtani Adel A. , Rahim Zillur , Masrahy Mohammed , Al-Malki Bandar H. , Al-Kanaan Adnan A. 
Published: May 2011

Abstract
The Unayzah reservoir in SA-1 field is highly unconsolidated with heterogeneous sequence of Early Permian sandstones saturated with condensate rich gas. Reservoir characterization based on the seismic, geological, and petrophysical analysis has indicated many stratigraphic units within the main Unayzah-A interval, which consists of well developed Eolian sandstones represented by Eolian dunes, sandsheets and closely associated inter-dune and lake deposits. Due to the unconsolidated nature of reservoir rock, conventional drilling and completion pose a very high risk of producing formation sand along with gas production, which can cause immense damage to production string, wellhead, surface flow lines, and gas plant equipment. In the early development stage of SA-1, frac-pack (F&P) was used and had been successful for several years. The method consisted of creating a short fracture, packing it up with proppant, and placing a screen as part of the completion system across the reservoir section. After years of producing from wells completed with this F&P completion, the scale due to fines migration buildups in the proppant within the annulus and causes high positive skin and deterioration of the screen, and consequently, needs a complete workover to regain lost potential. The workover for a F&P well is nothing less than drilling a new sidetrack as the completion cannot be de-completed and pulled out.
After detailed study and modeling, it was decided to change this strategy and complete the wells with an expandable sand screen (ESS). The completions using the ESS were effective and successful in terms of trouble-free deployment of the equipment and sustained a long-term sand-free rate.
The conventional sand screen (CSS) assembly has also been used in this reservoir. The initial test of this equipment conducted in one of the high producers was successful; however, long-term sand-free production as well as maintaining screen integrity cannot be ascertained. Among the disadvantages of CSS completion is the possibility of wellbore collapse on the screens with the depletion of reservoir pressure (changing near-wellbore stress environment) during production life of the well. In such case, the screen can incur partial or total damage and can no longer resist sand production.
The paper describes in detail the reservoir characteristics and presents numerous examples of different completion methods implemented in the field to prevent sand and ensure high, sustainable flow rate. Long-term performance data are analyzed and presented in this paper to show the performance of sand screen technology.
Safe Execution of Sour Well Tests in the Kidan Field
Authors: Bellerby Philip , Hoekstra Taco , Elias Peter , Wevers Adrian 
Published: May 2011

Executive Summary
The South Rub Al-Khali Company Limited (SRAK) is an incorporated Joint Venture between Shell Saudi Ventures Limited (50% share) and Saudi Arabian Oil Company (50% share) to explore for non-associated gas and associated liquids in the South Rub’Al-Khali Basin (Empty Quarter) in the Kingdom of Saudi Arabia.
This paper describes the key HSE processes which were an integral part of the SRAK management system employed to achieve the safe execution of critical sour gas well tests.
SRAK has to date drilled two extremely sour, multiple reservoir wells. During the drilling phase, the H2S gas is kept – by design – down hole in order to minimize any exposure to personnel. However, during the production test phase the production of gas from these sour wells carries one of the highest risk factors in the oil industry. It requires meticulous planning and execution with strict adherence to established plans and procedures. Extensive training and competence assurance is required before allowing highly toxic gasses to flow to surface. These well tests have put the Kidan field onto the map as a potential commercial development, in spite of the high cost of remote desert area operations combined with the inherent complexity of the sour gas contained in the Kidan structures.
This paper will describe the numerous safety challenges involved in the testing of two highly sour wells, SRAK-A and SRAK-B. It also outlines the approach that was followed to ensure safety in design, execution and emergency response planning. Case histories will explain the effective handling of unplanned H2S gas release events on surface will be used to demonstrate the effectiveness of training and systems in place. Learning, and associated introduced improvements, will be described as part of an operational efficiency review.
Underbalanced Drilling (UBD) as a Tool to Test Tight Gas Plays – An Example from the Empty Quarter, Saudi Arabia: Drilling and Reservoir Characterisation Lessons
Authors: Al-Maashari Yousuf , Briner Andreas , Axon Andrew , Wevers Adrian 
Published: May 2011

Executive Summary
The South Rub Al-Khali Company Limited (SRAK) is an incorporated Joint Venture formed by Shell Saudi Ventures Limited (50% share) and Saudi Arabian Oil Company (50% share) to explore for non-associated gas and associated liquids in the South Rub’Al-Khali Basin (Empty Quarter) in the Kingdom of Saudi Arabia.
This paper discusses specific data acquisition strategies that have been developed to address the challenges of deep wells in tight reservoirs in remote and harsh environments. While drilling the first three wells SRAK has gone through a very steep learning curve with respect to well data acquisition and integration. It also allowed optimising the data acquisition strategy for future wells that SRAK was planning to drill.
As a direct result of this initial work, and the experience gained by other wells drilled in the Rub’ Al-Khali, SRAK realised that the traditional approach and formation evaluation using static well data gathering was not entirely satisfactory. Industry experience also showed that tight gas exploration and appraisal wells historically involved lengthy multi-year multi-well programs due to inconclusive results from static logging, coring and well testing operations.
In line with Shell's global initiative to use underbalanced drilling (UBD) for tight gas exploration and appraisal, UBD was implemented in SRAK's fifth exploration well in the Rub’Al-Khali. The deeper Palaeozoic reservoirs in the Rub’Al-Khali are known to be commonly tight and susceptible to near-wellbore formation impairment during conventional overbalanced drilling. UBD offered a possible solution for better quality reservoir evaluation and demonstrating any un-impaired potential flow. In other prospects, previous conventional drilling, stimulation and well clean-up had typically failed to unambiguously characterise pay and produce hydrocarbons to surface.
UBD drilling operations were designed and implemented with the support and expertise of the shareholders. Both internal and external subject matter experts supported operations. Whilst numerous UBD specific drilling related aspects were understood pre-drill, significant uncertainty remained around data acquisition and interpretation during UBD drilling operations.
The SRAK UBD project was safe and successfully executed as per the drilling program. Due to the UBD operations there was no ambiguity on presence and mobility of hydrocarbons, thereby avoiding SRAK the completion, fraccing and testing cost which are far higher than the UBD expenditure.
The well SRAK-F offered firsthand experience to the SRAK team to assess the advantage and disadvantage of UBD operations on reservoir characterisation. This paper aims to capture SRAK's learning in UBD drilling and reservoir characterisation.
Horizontal Wells Drilling Activity in South Texas Unconventional Gas Resources and Microseismic Hydraulic Fracturing Monitoring Application to Reduce Risk and Increases the Success Rate
Authors: Sani Abu M. , Ejefodomi Efe A. 
Published: May 2011

Abstract
Unconventional gas resource plays continue to have a significant impact on natural gas production in the US due to recent technological advances and higher demand for gas. In the US, 22% of the total energy consumed comes from natural gas. The US domestic production of natural gas is around 85% of the demand; currently about half of that comes from unconventional resources. Primary unconventional sources are tight gas, shale gas, and coalbed methane (CBM). Tight gas, shale gas and CBM production accounts for approximately 28%, 14% and 8%, respectively, of total US gas production. Total US production for 2010 is 21.57 tcf. Achieving sustainable production from unconventional gas resources requires reaching extended areas of the reservoir and performing effective hydraulic fracturing, with its associated technologies, to help reduce risk and increase the success rate.
Compared to production in vertical wells, the production of tight gas and shale gas in horizontal wells has increased significantly due to the ability to reach extended areas as a result of enhanced drilling technologies. Horizontal wells represent a large portion of the well count in US plays, with rigs for horizontal wells increasing from 10% to 58% of the total drilling rigs within the last 6 years (2005–2010). This increase in activity was achieved through careful engineering designs and use of new technologies to address the complexities involved in planning, drilling, completing, and stimulating horizontal wells. In recent years, microseismic hydraulic fracture monitoring (HFM) has become a key technology in understanding the propagation mechanism of the created fractures during stimulation treatments.
The paper discusses horizontal well drilling activity in a south Texas play over a 6-year period beginning in 2005. Drilling activity trends and completion practices in some tight gas and shale gas formations in the south Texas basin are highlighted. Additionally, the paper takes a look at the application of microseismic HFM to increase the success rate of horizontal wells in the south Texas basin by reducing some of the completion risks and challenges. Finally, the paper discusses ways to improve the overall completion and stimulation designs of horizontal wells in unconventional gas formations to ensure efficient recovery.
Successful Drilling and Deployment of an Open Hole Multistage Fracturing System in a Deep and Hostile Sandstone Gas Reservoir
Authors: Ab. Hamid Abdul Halim , Khalil Mohammed E. , Al-Mohammad A. K. , Al-Khamees Shaker A. , El-Mofty Wael , Johnston Bryan , Wilson Stuart 
Published: May 2011

Abstract
The pre-Khuff Unayzah gas reservoir in Saudi Arabia is a competent sandstone formation with Unayzah-A and B/C sand units separated by a variable thickness siltstone unit, which is regarded as a sealing barrier between the Unayzah-A and Unayzah-B reservoirs. They are known to contain significant reserves of natural gas, however they are at low permeability, which has made it difficult to optimize production. Drilling through highly abrasive sandstone at high bottom-hole temperatures (BHT) has also been challenging. To meet Saudi Arabia's future gas requirements, it was essential to establish a means to exploit these reserves.
Multiple methods have been used to drill and complete these wells, including long horizontals and multilaterals. Well trajectories were planned with the horizontal sections drilled along the direction of maximum in-situ stress (parallel to the fracture plane) for enhanced wellbore stability and fast penetration rates. Fracture treatments were pumped generating mostly longitudinal fractures propagating in the same direction as the maximum horizontal stress (parallel to the wellbore axis) resulting in a poor fracture network and suboptimal production results.
In April 2010, a horizontal well was successfully drilled into the Unayzah reservoir towards the minimum in-situ stress direction and completed with an open hole, multistage (OHMS) fracturing system. A four-stage proppant fracturing job was successfully conducted in November 2010 without issues. Unique fracture signatures were observed in each zone and production from the well has exceeded expectations.
This paper analyzes Saudi Aramco's successful initiative to drill the lateral section along the direction of minimum in-situ stress and the challenges associated with wellbore stability, a highly abrasive formation and high static BHT. Also highlighted are Saudi Aramco's successful techniques for deploying the OHMS fracturing system with special emphases on borehole preparation. Lessons from the successful drilling/completion of this well could have a significant impact on how future Unayzah wells are drilled and completed to maximize productivity from tight gas reservoirs in Saudi Arabia.
Advanced Cementing Systems for Deep Sour Gas Wells
Authors: Liu Z. , Sun J. , Nasr-El-Din H. A. , Shan H. , Xiao Z. 
Published: May 2011

Abstract
Cementing deep sour gas wells presents a number of challenges to well construction engineers. High bottom hole static temperature (BHST from 250 to 400°F) and pressure (mud density &gt; 2.0 g/cm3), excessively long job times due to the constraints imposed by tight annular clearances (casing OD/hole size &gt; 0.85), long cement columns (interval length &gt; 450 ft), and harsh conditions (H2S, CO2, salt layer, high leakoff). All of these factors contribute to the operational risks not only during placement of the cement slurry in the wellbore, but also during the life of the well. Field data indicates that current cement systems were not able to address these challenges, and as a result, the outcome obtained from various cementing jobs was below expectation.
Advanced cement systems were developed to address the problems encountered in cementing deep sour gas wells. These systems were applied in the field with great success. Multi-functional fluid migration control systems together with engineering particle sizing technique significantly improved the performance of cementing jobs, including: superior fluid migration control, predictable thickening time, stable API properties at high slurry densities, and great resistance to H2S, CO2 and salt corrosion. A unique retarder used in the lead slurry helped in developing compressive strength rapidly on the top of cement column. An effective laminar flow displacement technique was also used to displace drilling fluids effectively to enhance its placement and improve the cementing bond.
This paper details a thorough and systematic laboratory development of innovative cement systems and presents case histories to document their effectiveness for cementing deep sour gas wells.
Success Criteria for Multistage Fracturing of Tight Gas in Saudi Arabia
Authors: Rahim Zillur , Al-Kanaan Adnan , Johnston Bryan , Wilson Stuart , Al-Anazi Hamoud , Kalinin Daniel 
Published: May 2011

Abstract
The purpose of open-hole multi-stage (OHMS) fracturing is to improve hydrocarbon production and recovery in moderate to tight reservoirs. To date, 17 OHMS fracturing systems have been installed in deep gas carbonate and sandstone wells in Saudi Arabia. Of these, 14 installations have been stimulated (acid or proppant fractured) and flowed back.1 Overall, the production results from the use of OHMS systems deployed in the southern area gas fields have been very positive with some variation – most of the wells responded positively and are excellent producers (&gt;20 million standard cubic feet per day (MMscfd)), some showed average results, 8-12 MMscfd, and a few, completed in tight reservoir, produced at relatively low rates, &lt;3 MMscfd, and did not carry enough wellhead pressure to be connected to the production grid. This paper will explore the factors that impact successful OHMS completion systems. Some important factors include types of OHMS used, formation properties, completion liner size, packer types, number and size of stimulation stages, treatment types, well azimuth, and fluids pumped. Conclusions are drawn based on careful data analysis to confirm the best practice for successful OHMS deployment and conducting effective fracture treatment.
This paper uses extensive field data and correlates factors to show the applicability of OHMS technology. Analysis will cover pre- and post-stimulation data showing the results from the treatments. This analysis will show the factors that contribute to successful deployment of the completion system, higher production rate, and the choice of the right candidates to obtain positive results from the treatment. This paper will show that while the various well and reservoir characteristics have a significant influence on overall well productivity, the completion type is critical and plays a central role on the success of the stimulation treatment and final production levels.
OHMS systems have been deployed extensively in North America, but they are relatively new in the Middle East. This is because the conventional horizontal wells are usually high producers and only require small stimulation treatment to clean up the near wellbore area from drill-in induced damage. With the exploration of tight gas and unconventional resources, the need to conduct multi-stage fracturing (MSF) is increasing. The tight gas zones in Saudi Arabia are typically deeper and more complex with higher temperatures and pressures than most tight gas zones in North America and therefore require much more accuracy and precision in OHMS technology applications. This paper discusses the factors that contribute to the higher production levels for these types of completion systems.
Effects of Carbon Dioxide Injection in Reactive Carbonates: Computational Rock Physics Basis for Time-Lapse Monitoring
Authors: Nur Amos , Vanorio Tiziana , Diaz Elizabeth 
Published: May 2011

Abstract
Carbon dioxide injection into natural reservoirs has been used for enhanced oil recovery as well as, more recently, for geologic sequestration. In both technological applications, of major interest is remote sensing of the progress of the injected carbon dioxide through the subsurface as well as its effects on the physical characteristics of the rock, including the elastic, storage, and transport properties. Whereas it may be safe to assume that the presence of carbon dioxide does not alter the mineral matrix in most clastic reservoirs, the situation is very different in carbonates where such alteration may occur in real time, in a matter of hours, days and, certainly, months.
Physical laboratory experiments have confirmed that the carbon dioxide interacts with formation water and, eventually, with the mineral matrix (Vanorio, T. et all, 2008). These chemical processes alter the pore space geometry in carbonates and can even create such flow conduits as relatively large wormholes. This pore-space and matrix alterations can definitely affect the elastic properties of carbonate rock, which are crucial in interpreting the 4D time-lapse seismic data for pore-fluid content in space and time. Because of the changes occurring in the mineral matrix during carbon dioxide injection, traditional fluid-substitution techniques often do not work in such reactive rock and, hence, can be misleading during seismic data interpretation.
Fluid Flow Characterization of Chemical EOR Flooding: A Computerized Tomography (CT) Scan Study
Authors: Bataweel M. A. , Nasr-El-Din H. A. , Schechter D. S. 
Published: May 2011

Abstract
Chemical flooding methods are used to recover residual oil left after water flooding. Several recovery mechanisms were suggested to improve the displacement effectiveness of the trapped oil. Reducing IFT, mobility control and wettability alteration are the main recovery mechanisms during chemical flooding. Understanding which recovery mechanism that dominate during recovery process helps selecting and optimizing which chemical process to be used.
An experimental study of 4 chemical flood experiments were visualized with computed tomography (CT) in sandstone cores at room temperature. The experiments were conducted to study four different chemical flooding processes: polymer, surfactant, surfactant-polymer (SP), and alkali-surfactant-polymer (ASP). Oil recovery, and oil distribution in the core were evaluated after the chemical flood.
The experimental results obtained from the core flooding experiment shows best recovery was during ASP and SP flooding with some residual reduction in permeability caused by using polymers. The lowest recovery was obtained during surfactant flooding, which prove that IFT reduction can’t improve recovery without the aid of mobility control by polymers.
Understanding Heavy Oil Fluid Sensitivity for Seismic Reservoir Characterization in Middle East Carbonates
Authors: Bakhorji Aiman M. , Otaibi Mohammad G. , Ahmed Mohammad Mukarram 
Published: May 2011

Abstract
Heavy oil is defined as viscous fluid having an API gravity of less than 22°. Seismic velocities are sensitive to heavy oil properties and especially to reservoir properties, such as temperature and pressure. Laboratory studies have shown that heavy oils with much lower API values can act as a semi-solid, and therefore support shear wave propagation. In such cases, using a conventional Gassmann fluid substitution model (Gassmann, 1951) to understand the fluid scenarios is not applicable for seismic reservoir characterization.
From the different published approaches for modeling fluid behavior in heavy oil reservoirs, the extended Gassmann (Ciz and Shapiro, 2007) is normally used as a lower bound (for low frequency and moderate fluid shear modulus change) for fluid substitution sensitivity and the Coherent Potential Approximation (Berryman, 1999) is used as an approximate upper bound (for high frequency). The true fluid substitution sensitivity for heavy oil is somewhere between these two bounds. A recently developed non-Gassmann rock physics workflow, in principle, provides a consistent approach to estimate (from calibration data, e.g., log data, core measurements) and model the data within these two elastic bounds.
A pilot study was undertaken to understand heavy oil's elastic properties in a Mesozoic carbonate reservoir located in Saudi Arabia. Due to the lack of core-fluid measurements, a range of heavy oil fluid parameters, such as gas-oil ratio (GOR), temperature, pressure and API range were tested to understand their effects on the elastic properties.
Stability of Local-equilibrium Foam States in EOR Processes
Authors: Ashoori E. , Marchesin D. , Rossen W. R. 
Published: May 2011

Abstract
The use of foam for mobility control is a promising mean to improve sweep efficiency in EOR. Experimental studies discovered that foam exhibits three different states (weak foam, intermediate foam, and strong foam). The intermediate foam state is found to be unstable in the lab whereas the weak- and strong-foam states are stable.
The model of Kam (Colloids Surfaces A, 2008) is the only mechanistic foam model that can fit a variety of steady-state experimental data including multiple steady states. This model is modified from a previous mechanistic foam model to resolve the intrinsic instability of the strong-foam state. Simple finite-difference simulations have found that an arbitrary perturbation grows for the unstable intermediate foam but diminishes for the strong- and weak-foam states.
The issue of the stability of foam states, especially the strong-foam state, is a serious concern in application of foam in EOR. Instabilities may rule out one or more states and consequently have considerable effect on reservoir sweep efficiency and injection pressure.
Here, for the first time the stability of the various foam states is investigated by a semi-analytical stability-analysis method. We demonstrate the instability of most intermediate states, consistent with the laboratory observations. However, fine analysis reveals a slight instability of the strong-foam state. We show that the diffusion, whether introduced artificially by the finite-difference scheme or representing physical dispersion, damps this slight instability. We obtain good agreement with finite-element simulations with and without diffusion.