bluuebunny/crossref_metadata_2025_split huggingface dataset:
Minimizing Dynamic Dysfunctions Sets New Drilling Performance Benchmark in Saudi Gas Application
Authors: Brackin Van , Doster Mike , Mounzer Fadi , Alfonzo Luani 
Published: May 2009

Abstract
The myriad drilling problems associated with dynamic dysfunctions, including substandard performance and premature bit and downhole tool failure, have been well documented in the literature. Alleviating these problems and potential failures requires a systems approach that brings together improvements in the bit, BHA, and operating practices.
This paper describes one such approach where a new-generation 16-in. PDC drill bit was applied in tandem with a newly engineered 12 ¾-in. positive displacement motor (PDM) and hard rock drilling techniques. Further, the high RPM and low weight-on-bit (WOB) recommendations inherent in old-school shale drilling gave way to hard rock parameters that maximized depth of cut. Consequently, impact fractures and abrasive wear were reduced, thereby maintaining the bit in an overall sharper and more efficient condition. Through this systems approach, the operator successfully avoided premature bit and motor damage and achieved record ROP and reduced costs in a Saudi Arabia project.
Historically, most sections have required a cleanout run with a roller cone bit, followed by a PDC bit for drilling the first 4,800 ft, and another PDC bit to complete the interval. The combination of the new tools and precise drilling techniques has eliminated the complexity and costliness of such runs. In a rare shoe-to-shoe run, the combination drilled out the 18 5/8-in. casing to TD at a record ROP of 33.8 ft/hr, replacing the three planned bit runs and saving the operator US $249,000.
The authors will explain the advances in PDC bit technology that focused on minimizing cutter damage, thus allowing bits to drill further at faster ROP. Further, they will examine ongoing initiatives aimed at improving performance and reliability in demanding drilling conditions that resulted in the development of the new and more robust PDM that provides higher torque output at available flow rates and pressures. They will describe how the new PDC bit technology and higher torque PDMs, combined with a change in operating procedures that focused on minimizing dynamic dysfunctions, resulted in a step change in performance.
Experimental and Numerical Study on Production Performance: Case of Horizontal and Dual-Lateral Wells
Authors: Amro Mohammed M. , Benzagouta Mohamed S. , Ayyad Hazim A. , Hussain Mofazzal 
Published: May 2009

Abstract
Current drilling technology is moving towards maximum reservoir contact (MRC) by means of extended-reach horizontal and multilateral wells in all types and shapes. Horizontal and Multilateral applications become more commonplace to improve the well productivity by providing maximum reservoir contact, minimizing operating costs, lowering the pressure drawdown and maximizing profitability. This paper presents the results of a numerical study performed to determine the production performance of dual opposed laterals compared to horizontal wells. With a total section exposed to the reservoir equal in both types, an experimental model has been built for the purpose of studying the production performance of the abovementioned well configurations. Production performance, in both systems, has been compared using numerical and physical model.
Results have proven that the dual-lateral well configuration accelerates the oil recovery by 90% in the early stage of production, compared to the horizontal well. Thus, the oil recovery using dual-lateral remains higher than that of horizontal well as water cut increases. Production performance for both configurations becomes equal in case of complete water production.
However, the numerical model shows that the dual-lateral accelerates the oil recovery by 10% compared to the horizontal well performance. Nevertheless, the results of the experimental runs indicate higher recovery values at early production stage compared to the numerical mode results. Such results confirm that dual-lateral wells are more efficient compared to the horizontal wells, where the optimum horizontal length is exceeded. Details of the optimum horizontal well length are presented. The paper provides also advantages of drilling dual-lateral wells compared to the horizontal wells exceeding the optimum lengths.
Production Enhancement of Cased-Hole Wells Using Mesophase Fluids
Authors: Christian Chad F. , Quintero Lirio , Clark David E. , Jones Tom A. 
Published: May 2009

Abstract
Formation damage is a by-product of the drilling, completion and production process that can be attributed to many factors. In cased-hole wells, the reservoir pressure and hence hydrocarbon flow may be impeded by various damaging mechanisms caused by the drill-in fluid filtrate, in-situ emulsions, water block, and organic deposition.
Mesophase chemistry has been developed to remove near-wellbore skin damage in perforated cased-hole applications. This fluid chemistry can be utilized as a perforating fluid and/or be applied during remediation operations to remove the formation damage around the perforation tunnels and/or fracture channels. The physical properties of this mesophase fluid include high oil solubilization, high rates of diffusion through porous media, and the reduction of interfacial tension to near zero between organic and aqueous phases, making them excellent fluids for removing formation damage.
This paper presents the development and case histories from numerous field applications that demonstrate the efficiency of mesophase chemistry to reduce skin damage and improve well productivity.
Successful Utilization of Fiber Optic Telemetry Enabled Coiled Tubing for Water Shut-off on a Horizontal Oil Well in Ghawar Field
Authors: Al-Zain Ahmed , Duarte Jorge , Haldar Surajit , Driweesh Saad , Al-Jandal Ahmed , Shammeri Faleh , Bugrov Vsevolod , Sarfraz Tashfeen 
Published: May 2009

Abstract
Water control is the key to prolong well life for economical and efficient oil recovery. When water reaches certain levels, oil production profitability decreases dramatically and even goes to negative. One feasible option in this case is a rigless water shut-off treatment, which involves an intensive process, starting from candidate selection and finishing with post-treatment well performance analysis. This kind of operation becomes more challenging for horizontal wells with open hole completion. Well A, a horizontal open hole producer with 2,440 ft of reservoir contact, was drilled and completed in November 2000. The last well production profile was determined by a Flow Scan Image (FSI) log, which showed 51% of water cut and the entry of most of the water was from the toe of the horizontal section. Based on economical and technical feasibility, fiber optic telemetry enabled coiled tubing (CT) was selected for an accurate and effective way to isolate the water producing interval, reduce water cut and enhance oil production.
The advanced and intelligent CT enables real time downhole measurements via fiber optic telemetry system. The system consists of surface readouts including dynamic interpretation software, fiber optic cable, and bottom-hole sensors, which provides Casing Collar Locator (CCL) readings, Distributed Temperature Survey (DTS), temperature, internal and external CT pressure measurements. Permanent zonal isolation, utilizing an inflatable packer with a cement plug above the packer, was successfully performed using CT conveyed fiber optic system. The availability of CCL, temperature and differential pressure readings enabled precise depth control, proper packer inflation and optimization of the cement design.
This paper highlights the application of a CT equipped with fiber optic advanced technology on a rigless water shut-off job. The paper also discusses the water shut-off (WSO) job design and execution challenges.
Differentiating Well Placement Expectations in Saudi Arabia with Production from Stringer Sand Reservoirs
Authors: Warran Phil , Mishrafi Nidal , Dossari Saleh M. , Butt Parvez J. , Javalagi Mohan , Jawad Waleed 
Published: May 2009

Abstract
Saudi Arabia is blessed with the world's largest onshore and offshore reservoirs. Currently Saudi Aramco is aggressively pursuing production increment ventures, one of the main components being the development of stringers which are present among all the major offshore oil fields. One of the technology contributions to Saudi Aramco's effort is proactive geo-steering using Directional and Deep Resistivity technology to maximize the net sand delivered from each well.
The drilling of development wells in sand stringers involves very thin and sinuous targets. These targets are the channel sand stringers and contain a substantial amount of hydrocarbons. Optimal well placement is a requirement for these very thin reservoirs in order to drain them in a cost effective manner.
Conventional well placement has met with limited success in stringers and thus resulted in low production figures. PeriScope has persistently proven that a proactive well placement technology can be translated into maximum reservoir contact, minimum well-bore tortuosity and a facilitator for optimal production.
Due to the uncertainty that is inherently present in the distribution of the channel sands, the prediction of the azimuth of channel meander can now be confidently solidified with new deep and directional electromagnetic measurements. By detecting the upper and lower conductive shale boundaries the wells can be steered in this very challenging environment of channel sands.
In the past two years Directional and Deep resistivity technology has delivered over 110,000ft of challenging reservoir to Saudi Aramco. This has also been an enabler for multi-segment collaborations and is now seen as a premium well placement service within Saudi Arabia. This paper will highlight how these innovative technologies have impacted the stringer sand reservoir development in multiple offshore oil fields of Saudi Arabia.
Cleanup of Oil-Based Mud Filter Cake Using an In-Situ Acid Generator System by a Single-Stage Treatment
Authors: Binmoqbil Khalid H. , Al-Otaibi Msalli A. , Al-Faifi Mohammad G. , Al-Khudair Waleed S. , Al-Aamri Ali D. 
Published: May 2009

Abstract
Near-wellbore formation damage is expected during the drilling operations. Minimization, prevention, and removal of near-wellbore damage are essential to maximize well productivity. One of the major sources of skin damage is the residual filter cake developed by reservoir drill-in fluid (DIF). Therefore, an efficient filter cake cleanup method should be considered to enhance well productivity. Oil producers in sandstone reservoirs are being drilled with invert emulsion DIF during oil reservoir drilling. Standard completion of oil wells is with stand-alone screens. Although screens stabilize the wellbore and address sand control issues, it can also act as a trap for filter cake, resulting in high drawdown pressure. An in-situ acid-precursor technology, which generates organic acid, was proposed to be used. The prime advantage of this technology, especially in long horizontal wells, is the uniform distribution of acid during precursor to remove oil-based mud (OBM) filter cake by a single-stage. A special surfactant blend was incorporated in the cleanup fluid to alter the wettablity of the oily filter cake, and therefore, facilitate the reactivity of the produced acid with calcium carbonate particles. Detailed lab studies were conducted to evaluate the efficiency of the in-situ acid generator technology. The lab studies include various tests to evaluate filter cake removal efficiency, return permeability on real core samples, compatibility with formation fluids, and strength of dissolving calcium carbonate particles. Based on lab results, it was recommended to spot the single-stage filter cake cleanup fluid as a treatment for an oil well. This paper will discuss in detail the laboratory work that was conducted to evaluate the filter cake cleanup fluid performance.
Case Study: First Successful Offshore ESP Project in Saudi Arabia
Authors: Al Zahrani Ahmed R. , Al-Nasser Redha H. , Collen Timothy W. , Khade Sudhakar 
Published: May 2009

Abstract
The Electrical Submersible Pump (ESP), a form of artificial lift technology, has proven to be a durable solution for delivering the required rates from Saudi Aramco fields. Therefore, this form of artificial lift was selected to increase production rate from one of the offshore fields, while optimizing offshore producing facilities. This offshore field has favourable conditions for ESP application, producing from carbonate reservoir with no anticipated fines production, low GOR, low temperature, low bubble point pressure and high API gravity.
All new installations were carried out without interrupting the ongoing production target. The project has completed a four-years operating cycle while continuously maintaining the field production rate with an acceptable ESP failure and run life.
So far, 41% of the originally installed ESP systems are operating more than 4 years and 20% are operating in the range of 3-4 years run life. The cumulative average run life of operating ESPs is 2.7 years and that of failed ESPs is 1.74 years. To maintain required production target, an effective ESP replacement program is a core element of field production strategy. Therefore, several measures such as replacement of underperforming ESP systems and upsizing of the pumps have been implemented. Furthermore, Dismantle Inspection and Failure Analysis (DIFA) of pulled ESP systems were conducted to evaluate the root cause of the failures and remedial actions were implemented to prevent such occurrences in future. Increasing Motor Lead Extension cable thickness, utilization of tandem seals and new wellhead penetrators are also expected to further enhance the ESP run life.
New applications to minimize ESP failures due to human intervention and ensure proper equipment handling during installations are being pursed. In addition, tandem ESP completions and different types of wellhead penetrators are being pursued to reduce rig utilization, increase producing life and minimize failures.
Gel under Dynamic Stress in Porous Media: New Insights using Computed Tomography
Authors: Al-Muntasheri Ghaithan A. , Zitha Pacelli L. J. 
Published: May 2009

Abstract
Crosslinked polymer gels are widely utilized to reduce water production from oil and gas producing wells. Zitha et al. (2002) developed a theory accounting for the basic mechanisms of gel extrusion by water through matrix porous media, i.e., compression, yield and flow. Their model predicted pressure drop and saturation changes over the gel-treated porous media during gel yield and extrusion by brine. The pressure drops were successfully compared to yield and displacement of an organically crosslinked gel formed insitu by water from Berea sandstone cores. This paper reports for the first time the measurements of saturation changes during such yield, and displacement experiments using X-ray Computed Tomography (CT) scanning. The experiments were performed using Bentheimer sandstone cores treated with gels containing 3 wt% polyacrylamide polymer (PAM) and 2 wt% polyethyleneimine crosslinker (PEI) shut-in at 55°C (131°F) for 22 hours under high pressure drops up to 89 bars (1,291 psi). Total organic carbon analyses indicated that no polymer retention or adsorption took place during gelant placement into Bentheimer sandstone cores. CT images indicated that the displacing brine saturations were independent of position, although, saturations increased with time. In addition, the breakthrough pressure occurred at a relatively later time compared to the critical pressure. New insights into the existing saturation models are given, which will provide a better understanding of the pressure and saturation changes with time.
R&D Role for Sustainable Production Operations
Authors: Guerillot Dominique R. , Al-Taie Ihsan , Pauchard Vincent , Raju Krishnam , Sanders Peter , Sherik Abdelmounam , Vilagines Regis 
Published: May 2009

Abstract
This paper reviews some of the Saudi Aramco R&D Projects for increasing the asset life expectancy of its production facilities. The ultimate objective is to deliver innovative solutions to address actual or anticipated problems encountered by operations. The Research and Development Center in Saudi Aramco has developed a generic delivery model consisting, for each project, of the identification of the following four main components: business need, value created, internal competencies and partners to provide solutions in a timely manner
The portfolio for the Upstream R&D Program for the production facilities is composed of several projects: The Crude Oil Separation project to improve the separation of the production into oil, gas and water phases.The Emulsion Mitigation project to handle specific problems related to emulsion from the near wellbore to the separation vessels included.The Water Systems project built with a holistic approach, to handle produced and injected water, and associated phenomena such as bacterial control and corrosion.The Scale Mitigation project to prevent and mitigate scale in oil and gas wells, for better injectivity and productivity.The Pipeline Integrity project, which includes a variety of issues such as sulfur deposition and blister control.The Black Powder Management project, a multi-disciplinary project to address this specific issue caused by corrosion for sales gas pipelines.
This paper will summarize the goals and deliverables of these projects. Further potential R&D projects for Production or Midstream related issues are also listed.
Horizontal Open Hole, Dual-Lateral Stimulation, Using a Multilateral Entry with High Jetting Tool
Authors: Amorocho Jose R. , Solares J. Ricardo , Al-Mulhim Abdulmohsin , Al-Saihati Ali , Kharrat Wassim 
Published: May 2009

Abstract
The number of multilateral gas producers drilled in the Ghawar field has significantly increased over the past few years as part of the reservoir development strategy to maximize well productivity through maximum reservoir contact. Although these wells are expected to require little rigless intervention to conduct surveillance or productivity enhancement work, the effective options available to selectively access each of the laterals are limited. Thus specialized tools and techniques are required but the complex nature of these deep wells, combined with the high pressure and temperature characteristics of the reservoir, makes their application difficult and the outcome of the well intervention procedures uncertain.
One of the techniques that has proven successful in different fields around the world, is the use of a lateral accessing tool to selectively access the desired lateral to then perform a stimulation treatment, run a production log, or any other operation. Combining lateral accessing and high-pressure jetting tools to access and stimulate two under-performing laterals a world first, was done in Well A, a producer drilled in a carbonate reservoir in Saudi Arabia's Ghawar field. The stimulation treatment was successful and the well achieved a two-fold rate increase.
This paper provides details about the pre-job research and testing conducted, the methodology, equipment and procedure successfully applied in dual-lateral Well A, and lessons learned throughout the operation. The post-treatment performance of the well was better than anticipated, which encouraged Saudi Aramco to further utilize the technique for different applications.
Use of Auto Diverter Valves in ESP Completed Oil Wells Which Produce Sand and Solids
Authors: Sipra Iqbal , Shotter Paul 
Published: May 2009

ABSTRACT
This paper is intended to present the experiences of PDO Oman using Pumptools’ ADV valves (Automatic Diverter Valve) in ESP completed wells that have sand and solids production. Short run times were repeatedly experienced in Oman due to the sand and solids falling back on top of the pump after the ESP had been switched off or tripped. Upon restart the sand plug on top of the pump caused damage and premature failure of the ESP.
The Pumptools Patented ADV was designed from the outset to address these route cause issues which have plagued ESP users for many years. This new technology tool is designed to enhance the run time of ESPs in sandy wells. The Tool was used in several fields in Oman where sand was being produced. This paper outlines the improvements seen as a result of utilizing the Pumptools Auto Diverter Valve (ADV).
Smart Well Production Optimization Using an Ensemble-Based Method
Authors: Su Ho-Jeen 
Published: May 2009

Abstract
Recently, the ensemble Kalman filter method (EnKF) has been successfully applied in assisted history matching. It is a very powerful tool and can handle a very large number of reservoir parameters, up to millions. The method is a Monte Carlo type formulation, and employs a covariance matrix and maximum a posteriori estimate theory. This new technology has been implemented into an industrial parallel reservoir simulator.
In this paper, we show its application to optimize two horizontal wells equipped with an inflow control valve (ICV) in a sector model of 200,000 cells. One hundred layers were used to capture geological heterogeneity. The two wells were drilled parallel to the edge-water boundary. The optimization objective is to minimize cumulative water production over a 10 year production period.
Encouraging results have been obtained. Cumulative water production was reduced 50% after only five optimization iterations. The optimized ICV opening variation over the entire production history is described. Verified by simulated water production results, the ensemble method did a satisfactory optimization job, better than a trial and error approach could provide. The fully-automated optimization process can be completed within a few hours under a parallel computing environment.
Development of Generalized Porosity-Permeability Transforms by Hydraulic Units for Carbonate Oil Reservoirs in Saudi Arabia
Authors: Shenawi Shamsuddin , Al-Mohammadi Hisham , Faqehy Muteb 
Published: May 2009

Abstract
There are several types of porosity-permeability transforms to determine permeability from well log-derived porosity in uncored oil and gas wells. Widely used typical transforms, either by geologic zones or by facies, do not provide satisfactory permeability to be distributed in reservoir simulation models. Hydraulic Unit (HU), which is a technique of rock typing of reservoir, provides far superior transforms than typical transforms. In this work, available routine core data, from major carbonate oil reservoirs located in eight different oil fields of the Kingdom of Saudi Arabia, are assembled to develop improved generalized porosity-permeability transforms by Hydraulic Units (HU).
Improved transforms by HUs were developed for major carbonate oil reservoirs in eight different oil fields. Correlation accuracy (R2) of each transform by HU was very good (&gt;0.9). Then all data from eight different fields were combined to develop generalized transforms by HU technique. This technique provided excellent transforms for various HUs regardless of rock fabrics—either limestone or dolomite.
Developed generalized transforms by HUs were tested for their accuracies on acquired core data in two wells, completed in the same major carbonate reservoir, but in two different oil fields. Applicability of generalized transforms was also tested with the core data from a different secondary carbonate reservoir. Calculated permeability by HUs matched very well with the tested core data which enhanced the reliability of developed generalized transforms.
Similarly, generalized vertical permeability transforms by HUs were developed for the same major carbonate reservoirs in eight fields. Calculated vertical permeability by HUs matched very well with core data as well. Then vertical to horizontal permeability ratios (kV/kH) by HUs were calculated using both generalized transforms for vertical and horizontal permeability. The kV/kH ratios for most of the HUs are found to be almost one under the laboratory condition.