bluuebunny/crossref_metadata_2025_split huggingface dataset:
Perforating Long Horizontal Section with Tractor Brings Significant Gains in Completion Efficiency
Authors: Badri Mohammed , Al-Hashami Ahmed , Al-Masroori Mohammed , Salsman Alan , Jumaat Mohd Shafie , Situmorang Haposan 
Published: September 2011

Abstract
Oman completion strategies continue to evolve as more cased horizontal wells are completed. These wells must be perforated and, for the best production performance, should be completed underbalance avoiding any kill as part of the process. Early wells were perforated using coiled tubing with mechanical sealed ballistic connector1 to shoot in underbalance conditions and retrieve the gun assembly without having to kill the well. While the use of Coiled Tubing is a very effective deployment method, the extreme trajectory of some wells requires that fluids to ease drag friction be pumped as part of the deployment process. These friction reducing fluids may damage the perforations resulting in poor productivity.
A new wireline tractor conveyance technology designed for the harsh, high shock application of perforating has been used to perforate a long horizontal well section in underbalance conditions. Detailed pre-job planning and modeling was carried out to ensure the job could be executed as desired. Also the "lessons learned" gained in a previous attempt to use this technology helped improve the delivery efficiency. The guns were deployed and retrieved under controlled conditions minimizing any perforation damage in addition to significantly reducing the running times compared to other conveyance methods used in previous wells.
Eighteen successful tractor runs were made deploying up to 18.9 m of 2 7/8" OD perforation guns per run shooting 253m of perforation interval. Operating time was reduced significantly compared to previous perforating operations and no additional formation damage was done to the perforations as part of the process. Subsequent well productivity was better than expected.
The success of this operation opens up a wide range of applications for perforating or other heavy duty and high shock applications for this tractor technology. In the future different deployment technologies can be combined with the tractor for conveyance to push even longer gun strings into highly deviated wells in "live well" conditions further improving completion efficiency.This paper will review the technical considerations and the detailed planning exercise that is required for a successful tractor perforating job as well as the operational requirements to minimize nonproductive time (NPT). This in turn will improve job planning and the likelyhood of operational success for future perforating jobs in this complex operating environment.
Integrated Well and Reservoir Surveillance in the PDO EOR Projects
Authors: Zwaan Marcel , Hartmans Rob , Saluja Jasmeet , Schoofs Stan , Rocco Guillermo , Saadi Faisal , Lopez Jorge , Ita Joel 
Published: September 2011

Abstract
PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. Well-planned and executed reservoir surveillance has proven in the past to add significantly to the production and ultimate recovery from reservoirs.
Because of progress in technology, in areas of data acquisition, processing and modeling techniques, well and reservoir surveillance data are increasingly used to optimize EOR processes. However, the interpretation of all data and integration into well and reservoir management workflows is still challenging. This paper describes the ongoing development of workflows for the interpretation, modeling and integration of surveillance data in three EOR projects. The surveillance methods include geomechanical modeling, thermal reservoir modeling, and monitoring through time-lapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging.
Integrated Workflow for Computer Assisted History Matching on a Channelized Reservoir
Authors: Peters Elisabeth , Wilschut Frank , Leeuwenburgh Olwijn , van Hooff Peter , Abbink Oscar 
Published: September 2011

Abstract
Increasingly computer assisted techniques are used for history matching reservoir models. Such methods will become indispensable in view of the increasing amount of information generated by intelligent wells, in which case manual interpretation becomes too time consuming. Also, with the increasing possibilities for controlling a reservoir, a better prediction of the reservoir behavior is very important. A technique that has received considerable attention lately is the Ensemble Kalman Filter (EnKF), which is a sequential updating technique based on the Bayesian notion of updating prior information with observations (measurements). The EnKF has already been proven to be useful for history matching of real fields. Some of the advantages of the EnKF are its sequential nature, the large number of parameters that can be estimated (10000+) and the fact that an uncertainty estimate is generated. The most important and time consuming step for anyone wanting to do a history match with the EnKF is creating the initial ensemble including defining all the proper initial uncertainties. This paper presents an integrated workflow for creating an initial ensemble for a channelized reservoir and updating the ensemble sequentially using the EnKF. The resulting ensemble of history matched models is then used to predict the expected production and associated uncertainty for a new production strategy. The quality of the prediction is compared to the predictions from a model which was history matched manually. The improved predictive capabilities of the models which were history matched with the EnKF allows for better optimization of the production strategy for the complex channel geometry. Moreover, the updated uncertainty estimate shows the risks involved with some of the newly proposed wells, which allows for better decision making.
Adjustable Gauge Stabilizer and Torque and Drag Reduction Tools Reduce Overall Drilling Times by at Least 20%: A Case Study
Authors: McCormick John E. , Osorio German , Andachi Jorge , Barth Megan 
Published: September 2011

Abstract
Drilling more efficiently has always been an important consideration throughout the industry, but with the ever more complex and far reaching wells that are being drilled today, it has reached the stage of being a critical factor in the economic viability of many projects. This has lead to the development of many tools and techniques which have enhanced the overall process of drilling deviated wells and helped to realize significant savings in drilling time and improvements in well geometry.
Two such developments are the adjustable gauge stabilizer (AGS) and torque-and-drag reduction tools, which provide a method of reducing drilling times in directional wells with build and tangent sections, thereby decreasing the cost while mitigating risk. An AGS eliminates the need to pull and replace the bottomhole assembly (BHA) after completing the build section, thereby saving one complete round trip. Torque-and-drag reduction tools enhance the ability to make directional adjustments while rotating and facilitate reaching well targets which high levels of torque and drag would otherwise prevent. As a result, the time spent drilling with a positive displacement motor (PDM) without pipe rotation (sliding) in the tangent section is mitigated, reducing overall drilling time for the section by an average of at least 20%.
This paper will discuss the evolution, design and operational characteristics of these tools and will present case studies of wells drilled in Ecuador where either the application of both adjustable-gauge stabilizers and torque-reduction tools, or the application of an AGS reduced drilling time when compared to offset wells drilled with conventional directional assemblies.
After Closure Analysis an Underutilized and Undervalued Approach to Understanding kh
Authors: Rylance Martin , Judd Tobias , Makmun Areiyando 
Published: September 2011

Abstract
For low permeability tight gas reservoirs, the fracture half length and the fracture dimensionless conductivity are the two principal design parameters, goals and characteristics that can be set; that have the greatest impact on the actual well productivity index. The fracture dimensionless conductivity compares the ability of the fracture to convey fluids along its length into the wellbore, versus the capability of the reservoir to support the flow of fluids into the fracture itself. However, in most cases, and certainly in an exploration and appraisal environment, the formation permeability and effective permeability thickness (kh) are often misunderstood, miscalculated and misapplied; subsequently impacting the fracture design process and therefore the overall well performance.
A large part of this exploration and appraisal process includes understanding the nature of, and gathering accurate data on, the reservoir performance itself; so that engineers can make the necessary informed decisions. In terms of estimating an accurate value for the effective permeability, techniques such as pre-frac pressure build ups and pressure draw-downs are probably the most common approaches taken; however these approaches can be operationally time intensive and costly, awkward to effectively execute and the data open to wide and non-unique interpretation.
As a result, the industry developed (some time ago), the little used process of pre-frac injection tests; to help identify formation transmissibility and reservoir pressure. This operation consists of the injection of a small amount of fluid into the formation at low rates and accurately recording the formation response during the pressure decline. From analysis of this data, it is relatively straightforward to calculate the effective formation kh (to reservoir fluid), optimize the hydraulic fracturing design, improve the reservoir model and more accurately perform post fracture well diagnostics.
This paper presents the application and results of such after-closure analysis (ACA), the impact of these calculations on the subsequent fracturing operations and finally their integration into a more comprehensive understanding of the fracture/reservoir performance and deliveribility.
Innovative Technique to Prevent Post-Fracturing Water Production using Relative Permeability Modifiers
Authors: Ali Ahmed , Amer Mohamed , Yassine Rami , Abdel-Khalek Tamer , Hamdy Ahmed 
Published: September 2011

Abstract
Hydraulic fracturing has been used for a long time in the Egyptian western-desert reservoirs and has proven to be very beneficial in increasing well productivity by approximately 25% over that of wells completed without hydraulic fracturing. However, production of water caused by fracture growth into the adjacent underlying (or overlying) water zones to the hydrocarbon zone is a major challenge.
Excessive water production threatens the economics of a well by Shortening its production life by trapping the hydrocarbon reservesIncreasing disposal and lifting costs that can reach up to an estimate of billions of dollars, partially attributed to water-disposal regulationsBoosting fines-migration problemsIncreasing the rate of tubular corrosion and scale buildup
These can be sufficient reasons to not consider fracturing in marginal fields.
The conformance-while-fracturing (CWF) technique incorporates a relative permeability modifier (RPM) in the fracturing-fluids design. The RPM provides a reduction in effective permeability to water without significant changes to the relative permeability to oil. Applying the CWF technique resulted in water cut as low as 4%, even when the adjacent water zones were within 10 ft of the perforations. This technique provides a tremendous economic boost and has been found to be an effective solution for fields otherwise plagued with water production. Increased recoverable reserves are now being observed from these wells. This paper discusses the geological and reservoir parameters of the wells and zones of interest, the properties of the RPM, the CWF job-design considerations (and the associated challenges to the job design), its field applications, and post-fracturing results in comparison to offset wells fractured conventionally in the same reservoir and at the same level. It is envisaged that CWF techniques will prove to be beneficial to other operators facing similar production challenges.
Mitigating Compaction Damage Through Real-Time Strain Monitoring at the Sandface
Authors: Earles Denise M. , Stoesz Carl W. , Pearce Jeremy G. , DeJongh Hans A. 
Published: September 2011

Abstract
Subsurface geo-mechanical stresses can cause formation faults, slippage, and compaction. These movements result in well failures, impacting production and resulting in significant expense and lost revenue. Traditional means for detecting such failures are limited and usually require interrupting production to re-enter the well, resulting in late detection of the problem and limited counteractive options.
A fiber optic support device has been developed to permanently monitor strain and temperature on sand screen products for gravel-pack and frac-pack applications. This technology, especially when paired with an optical wet connect, provides for long-term reservoir monitoring at the sandface, resulting in early detection of subsurface movements at a high resolution. With this information, operators can plan early mitigative actions, and monitor the results of these actions in real time.
This fiber support device provides a means of holding a helically wrapped optic fiber rigidly in place at the sandface, with no negative impact on the sand control functionality of the sand screens. New techniques were developed to manufacture this technology, as well as a new method to install the fiber. Dry connects have also been developed to allow connections between individual sand screens and enable longer monitored intervals.
The paper will describe this new technology, review the case history, including initial field trials, and discuss potential applications.
Engineered Particle Size Distribution While Drilling Helped Minimize Wellbore Damage in Sandstone Reservoirs
Authors: Mohamed Monir 
Published: September 2011

Abstract
Inducing formation damage in sandstone reservoirs through poor drilling fluids management can negatively affect well productivity. A detailed mud management plan that addresses fluid design and particle size monitoring can help minimize formation damage and improve well productivity. This was demonstrated successfully on 29 wells where the operator implemented an engineered oil-based drill-in fluid (DIF) and a particle size distribution (PSD) analyzer in the field while drilling the reservoir.
The oil-based DIF was formulated with a 70/30 oil/water ratio (OWR) and then treated with a sized calcium carbonate bridging agent to minimize spurt and total fluid loss. The PSD analyzer was used to continuously monitor and maintain optimal PSD values in the DIF. In addition, core samples were examined using a scanning electron microscope (SEM) to determine an average pore size value. The bridging agent treatment was engineered to help minimize formation damage that results from the invasion of fines, or colloidal solids. Overbalance pressures were also minimized to avoid the risk of differential sticking. The reservoir section was drilled with controlled rates of penetration.
To achieve better bridging results, D90, D50 and D10 particle size distributions were maintained in the programmed range throughout the entire reservoir section. Upon reaching total depth (TD), the bottomhole assembly (BHA) was changed to a reaming assembly and the entire open-hole section was reamed to TD.
After the open hole was deemed in good condition, the well was displaced to a solids-free invert emulsion mud with the same density as the DIF.
A total of 29 wells have been successfully drilled and completed with sand screens using this mud management plan. Testing results indicated minimum skin damage and good stable production rates.
Real-Time Operations Portal (Nibras): Another Step En Route to a Smart Field Management
Authors: Shihab Sufyan , Khadhuri Shaikhan , Busaidy Salim , Bettembourg Solenn 
Published: September 2011

Abstract
Managing oil fields in the best way possible has always been in the centre of interests for various oil companies; production maintenance and optimisation, deferment minimisation, efficient monitoring of well reservoir & facility performances, cross-function collaboration, and many other related issues, all represent the building blocks in a successful and efficient field management structure. The Fahud cluster of Petroleum Development of Oman has been running for more than four decades, and still contributes significantly to the company's total production. Hence, it is becoming more important than ever to ensure that the field is managed both optimally and efficiently to adequately handle the large stock of wells and facility units, and all other related issues, such as operations, services, human resources, etc. For this, a series of initiatives were adopted with the aim of achieving an efficiently monitored & controlled asset as well as highly synchronised multi-team actions.
In this paper, a web-portal based tool is presented; Nibras is a "smart" platform for Well & Reservoir Management (WRM). The standard data sources, web-accessibility, multi-levels of data presentation, exception-based surveillance, and compatibility with third-party tools, are just some of the many features and capabilities that Nibras possesses. These features has made it possible to detect problems and\or outstanding issues earlier, react to them faster, and thus decide better. Nibras has become a key enabler of the Fahud Collaboration Centre (the first operational collaborative work environment in Petroleum Development of Oman), as it provides a common ground for various asset teams from which data and information can be retrieved from standard sources. This has eliminated confusion and miscommunication that may typically result from referring to different tools, retrieving data from different sources, and presenting data in different formats.
Nibras has been approved for pan-PDO implementation, as it represents a leap towards a smarter management of oil fields. The implementation of Nibras –alongside other smart initiatives- has resulted in reduced well downtime (and hence reduced deferments), early detection of problems, more efficient decision making, and better cross-team knowledge sharing.
Utilizing NMR and Formation Pressure Testing While Drilling to Place Water Injectors Optimally in a Field in Saudi Arabia
Authors: Al-Shehri Dhafer , Kanfar Mohammed , Al-Ansari Yusuf , Abu Faizal Syed 
Published: September 2011

Abstract
The presence of tar or heavy oil that does not flow using conventional production technologies brings numerous challenges during field developments. Tar, acting as a permeability barrier, would often break flow or pressure communication from the aquifer to the oil zone. This results in inadequate pressure support, which is necessary for sustaining production levels and maximizing oil recovery. One of the key issues in developing a field with known tar mat accumulation is to optimally place injectors away from the tar. The problem becomes more complicated when the exact location of a tar mat is uncertain either laterally or vertically. Tar mats usually are neither flat nor uniform in thickness across a field. These uncertainties pose a challenge in planning wells especially water injectors.
Detection of tar is critical for reservoir characterization, reserves calculation and well placement. Direct and indirect techniques are employed to detect tar including core analysis, well testing, wireline logging and Pyrolitic Oil Productivity Index (POPI). These measurements are good indicators of tar; however, the challenge is to identify the tar while drilling the well. Early detection requires the deployment of logging while drilling (LWD) technologies for real-time interpretation of data.
In order to accurately identify tar in reservoir sections in real-time, integrating conventional LWD measurements with new technologies such as the slim hole Nuclear Magnetic Resonance (NMR) and the formation pressure measurements while drilling (FPWD) is necessary. This will allow for timely adjustment to the well path and prevent costly remedial actions
This paper discusses successful real-time application of slim-hole NMR and FPWD technologies to detect tar and optimally place water injectors. This is demonstrated with two case studies involving extended reach power water injectors.
Using Streamline and Reservoir Simulation to Improve Waterflood Management
Authors: Al-Zawawi Ahmed S. , Hayder M. Ehtesham , Baddourah Majdi A. , Abd Karim Mohd Ghazali , Hidayat Wahyu 
Published: September 2011

Abstract
Streamlines provide snapshots of flow patterns in the field, which simulation engineers can use to shorten the history match cycle when validating reservoir models. They can also help engineers develop injection strategies and improve the sweep efficiency by analyzing flow patterns and by estimating injector to producer relationships in the field during computations of various prediction scenarios. Our strategy in this study is to use details of reservoir conditions obtained by traditional reservoir simulations and calculate streamlines from the computed flow field. Saudi Aramco's in-house developed simulator POWERS and its post processing environment have been enhanced to generate streamlines from computed reservoir flow fields. A streamline tracing software developed at Texas A&M University and POWERS has been customized to generate streamline outputs. The algorithm used for computations is parallelized to run on Linux clusters. Several features, such as computations of injector/producer allocation factor and injector efficiencies, have been implemented in our streamline generation tool kit. In this paper, we present two case studies to illustrate advantages of streamlines when used in a workflow along with reservoir simulations to improve water flow managements of the field. Our analysis resulted in an optimal design with a fewer number of injectors to maintain the production target. In addition, streamline analysis helped us to find optimal well locations for injectors.