bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Cement System for Acid Gas Injection Wells
Authors: Fakhreldin Y. , Al-Sharji H. , Ruwehy A. M. , Saadi K. , Taoutaou Salim , Al-Kalbani Sultan 
Published: February 2011

Abstract
Petroleum Development Oman, PDO, is planning to improve ultimate recovery of condensate from a retrograde condensate gas field by reducing the rate of reservoir pressure decline. This shall be accomplished by re-injecting into the reservoir some of the produced gas and all of the acid gas extracted from the sweetening process. The composition of the injected gas will vary over time, from 15% CO2 and 3% H2S to 56% CO2 and 10% H2S. These combinations of CO2 and H2S can cause the wells cement to deteriorate. Portland cement tends to strongly degrade once exposed to such acid gases by reacting with calcium hydroxide formed from hydrated calcium silicate phases. As carbonates are dissolved in a low pH environment, the cement-carbonation products will not act as a self-plugging agent / s in the cement sheath. The resulting decrease of compressive strength and increase of permeability could lead to loss of zonal isolation and casing corrosion. These requirements led PDO to investigate and trial CO2-resistant cement to enable zonal isolation and ensure long term containment of the reservoir fluids. The nominated new technology cement system was trailed in a deep gas well which penetrated a reservoir which has high concentrations of CO2 and H2S at a super critical condition. The CBL/VDL log which was run after well completion showed excellent results. The well-cement quality shall be re-logged prior to any zonal shutoff work-over or well decommissioning. This paper will discuss the design, execution, and evaluation of the first acid gas resistant cement in PDO in one of the high profile gas well in South of Sultanate of Oman.
Technical Evaluations to Support the Decision to Reinject Produced Water
Authors: Zuluaga E. , Evans P. , Nesom P. , Spratt T. , Daniels E. 
Published: February 2011

Abstract
The industry is moving away from overboard discharging of produced water and is increasingly selecting produced water reinjection (PWRI) as the preferred method for waterflooding projects. This does not come without risks as the produced water usually needs to be supplemented by seawater in order to meet injection volume requirements, which increases the risk of both scaling and souring.
PWRI supplemented by seawater was the selected produced water management strategy for Field M located in West Africa. Produced water from the adjacent Field K is also being considered for reinjection into Field M. Field M will be waterflooded from the beginning to maintain reservoir pressure close to the bubble point. Recent experiences of PWRI in other assets have created a challenging atmosphere as scaling posed a major risk to production. Field M had to go through very detailed and though souring and scaling evaluations to justify the feasibility of this project.
A consistent formation water chemistry analysis for these evaluations was obtained by incorporating thermodynamic equilibrium constraints on formation water composition from reservoir mineralogy and using knowledge of basin formation water contributions from proximal salt formations. The evaluation of scaling potential was done using ScaleSoftPitzer. The results show a low risk of scaling when the waters are commingled. Periodic formation scale squeezes are recommended to mitigate the scaling potential.
The souring potential study was conducted using a full field reservoir souring simulation model (SourSimRL). SourSimRL superimposes criteria for the generation, partitioning and transport of H2S. Based on the results, the souring potential is predicted to be generally moderate. The souring potential for the field is restricted by the availability of carbon nutrients in the injection waters and the high reservoir temperature of 250 °F.
These rigorous technical evaluations were instrumental to obtain the support for PWRI and could be used as guidance for other PWRI projects.
Flow Quality Indicator (FQI): An Innovative Approach to Permeability Prediction
Authors: Akam Somadina Azuka , Maher Tom , Schell Christiane , Arnott Stuart 
Published: February 2011

Abstract
The Flow Quality Indicator (FQI) is an innovative but simple approach to permeability prediction, developed in response to modeling and production accounting issues. The FQI theory is that, in its simplest form in a unit reservoir, three parameters, in combination, determine the flow quality - porosity, volume of impermeable member, Vimp, and the remaining grain volume or "permeable member", Vpm. FQI postulates that Vpm must expand or contract with variations in Vimp and porosity. This variation is demonstrated to be unique property of any reservoir.
By relating FQI to measured core permeability or an independent measure of reservoir quality, the resultant empirical relationship has been established as a simple predictor of permeability in the absence of core data.
Two empirical model types - quadratic and linear – have been developed from core data in Baram Delta and Sabah (Malaysia). Results from either type do not show significant differences but the quadratic model has been found more suitable for highly laminated thin bed clastic environments below log resolution. The linear model has a more general application in most clastic depositional settings where formation beds are close to log resolution or larger.
The FQI concept has implicit universality, as demonstrated by several successful tests in the Baram Delta (Malaysia), Brunei and the Niger Delta (Nigeria). Coefficients of the function may be fine-tuned using an FQI modeling tool. However, it has been shown that only limited fine-tuning is required for most environments.
The FQI approach offers significant advantages compared with alternative models for permeability prediction (such as the Flow Zone Indicator, FZI), namely: (1) the input variables (Vsh, Φ) can be readily determined from conventional logs; (2) permeability estimation is quick and comprehensive; and (3) the method is applicable over a wide variety of clastic geological environments.
Alternative Training Tactics Provide Deeper Understanding of PDM Principles for Field Operators
Authors: Wakefield Sarah , Matta Stefanie 
Published: February 2011

Abstract
The widespread and longstanding use of the positive displacement motor (PDM) in thru-tubing and other oilfield applications means many tool operators have achieved a measure of both proficiency and confidence with running PDMs. But do operators really understand the mechanics of what makes the PDM work?
The introduction of newer, competing technologies such as turbines for downhole applications means operators and customers now have a choice between different technologies to meet their need for a downhole drive system. Each technology offers different benefits and limitations. To make the right choice for the job situation and for the customer, field operators must have more than just a surface level understanding of the differences between the tools. A training program that would provide operators a deeper understanding of the PDM was required to help meet this need.
Typical ‘tool’ or product training focuses on each tool and lists the features, benefits and limitations of that tool in a lecture format. Retention of knowledge by adult learners in this type of lecture format is typically low. For our situation, we needed to ensure students not only recalled basic information about the PDM, but also learned and retained enough knowledge about the inner workings of the tool to make informed choices while operating on the job.
We chose to apply adult learning principles such as interactivity, repetition and motivation in the development of our PDM classroom-based technical training. From student presentations detailing the motor's internal design to simple visualization exercises using a pencil to demonstrate the movement of the rotor within the stator, we appealed to several different learning styles throughout the training. Survey results offered evidence that the alternative training tactics provided the students a deeper understanding of the PDM.
Information provided in the paper can benefit PDM field operators as well as developers and facilitators of technical training programs throughout the industry. Adoption of adult learning principles as a basis of technical training development can provide excellent results for classroom applications.
Deepwater Developments: Challenging Equipment Limits
Authors: Gordon Jeanette , Saicic Petar , McAllan Robert 
Published: February 2011

Abstract
This paper reviews an operator’s deepwater drilling campaign in Gabon and Equatorial Guinea and the principles that were established to ensure success through optimized performance.
Due to the economics involved in deepwater drilling notably the availability of suitable high specification drilling units, (and the corresponding high operating costs and mobilization times) operators with short exploration campaigns are responsive to considering the use of lesser specification vessels with a different well construction philosophy as a means of both optimizing performance and safely undertaking a project.
For this particular case study, the operator implemented current proven technologies in new ways to extend the previously regarded equipment limitations of a vessel thus providing a fit for purpose and safe solution to the financial and operational roadblocks which could have hampered the project. Specifically the implementation of surface BOP’s on a dynamically positioned drillship along with riserless drilling and evaluation of a shallow gas reservoir well. The key principles employed that ensured a successful campaign were;
Thorough well planning and risk assessment processes Establishing a high objective. i.e. "technical limit" Adapting and innovating to a given situation Logistical planning
The principles employed in this particular success case can be implemented for any project or task in a variety of industries or applications. Ultimately success was attained through thorough planning and subsequently successful execution of the plan.
The result was that this operator was able to drill five wells in the same amount of time as other operators had taken to drill only one well. This paper will detail how world record breaking performance in a deepwater environment was achieved.
Waxy Crude Production Management in a Deepwater Subsea Environment
Authors: Suppiah S. , Ahmad A. , Alderson C. , Akbarzadeh K. , Gao J. , Shorthouse J. , Khan I. A. , Forde C. , Jamaluddin A. 
Published: February 2011

Abstract
Systematic experimental and modeling approaches to designing a safe operating strategy for a 5-km deepwater subsea flowline case study are presented to address unplanned shutdown and restart events for waxy crude production. The measurements confirmed that the fluid behaves like Bingham plastic when it is allowed to become gel at the seabed temperature of 4 deg.C. The cool-down period was modeled using the transient simulator validated by measurements and was predicted to take 21 hours. The restart pressure was then modeled for both stock-tank and at line pressure conditions. These restart pressure requirements were found to be 2,500 psi and 2,100 psi, respectively for stock-tank and at line pressure conditions. Also, the use of inhibitor treatments demonstrated that the fluid would not form gel at the sea bed temperature of 4 deg. C. However, the current shut-in wellhead pressure of 2,500 psi is deemed adequate to restart the lines in the event of unplanned shutdown without the use of chemicals. The presence of a subsea pig-launching pump provides a safety factor for restart in case the line pressure is released to atmospheric conditions. Hence, the operating strategy does not require injection of wax inhibitors at the current state. However, in future when the shut-in wellhead pressure falls below 2,500 psi, the operating strategy is expected to be modified accordingly.
Maintain Well Productivity Through Inhibiting Scale Formation and Controlling Fines Migration
Authors: Nguyen P. D. , Vasquez J. E. , Weaver J. D. , Welton T. D. 
Published: February 2011

Abstract
Migration of fine particulates and/or scale formation is known to plug up etched channels or pore spaces in proppant packs, causing production decline in wells that have been acidized or completed with high-rate water packs or frac-packs. The removal of such damage caused by plugging is only a temporary solution if the source of the plugging material is not mitigated. This paper presents the results of a series of laboratory tests aimed at demonstrating and quantifying the performance of a treatment fluid for stabilizing formation fines, inhibiting scale formation, and keeping flow channels open through damaged proppant packs after production has been restored.
Packed beds of proppant and formation sands were used to simulate frac-pack conditions before and after remedial treatments. The treatment fluid was comprised of a salt-free, aqueous-based solution containing an environmental friendly clay-swelling inhibitor and a water-based agglomerating agent (WBAA). The results show that this WBAA system is applicable to most types of formations, including sandstones, carbonates, and coals. Once injected into the proppant pack and formation matrix, WBAA forms a thin film on the particulates, covering and anchoring them in place, without plugging pore throats. This thin coating does not harden, but remains flexible, allowing the treated formation to withstand high shear stress during high production flow rates. WBAA coating forms hydrophobic film-encapsulating particulate surfaces, inhibiting chemical reactions that lead to scale formation in the pack matrix.
The experimental results show that WBAA treatments effectively mitigate the buildup of scale in various sand packs and successfully control the migration of formation fines into proppant packs to maintain well production.
A Successful Application of Permanently Installed Distributed Temperature Sensing (DTS) for Optimization of Acid Treatment in Power Water Injector with Advanced Well Completion: Case Study
Authors: Sharma Hemant , Al-Zain Ahmed , Al-Salman Naji , Al-Harbi Mesaad , Said Rifat 
Published: February 2011

Abstract
With the advancement of technology and ease of drilling horizontal wells, producers/injectors are drilled with thousands of feet of horizontal section, to expose large reservoir areas for higher production/injection. To have a better flow distribution profile in heterogeneous formations, the producers/injectors are completed with Inflow Control Devices (ICDs) and external packers that provide compartmentalization to flow. The permanently installed distributed temperature sensing (DTS) fiber optic cable is externally attached to the completion, which is fed through the packers. This helps in obtaining distributed temperatures of all formations along the wellbore and throughout the horizontal section with high resolution. On-site analysis of the real time data from DTS could be used to optimize well treatments, such as acid stimulation.
This paper presents in depth analysis of an acid stimulation performed on a power water injector in a carbonate reservoir. The well is completed with ICDs, DTS and a Permanent Downhole Monitoring System (PDHMS) for well and reservoir monitoring. The real time data acquisition of distributed temperatures coupled with online interpretation through a special software helped in building temperature profiles. Analyses of the temperature profiles were used for proper placement of acid and diverter stages. The post acid stimulation result was very encouraging with a significant increase in the well injectivity and even flow distribution along the horizontal section. The experience obtained from this job has been used as a basis for future stimulation jobs.
Microseismic Mapping of Hydraulic Treatments in Coalbed-Methane CBM Formations: Challenges and Solutions
Authors: Zimmer Ulrich 
Published: February 2011

Abstract
Detecting and locating microseismic events that occur during a hydraulic treatment of a coalbed-methane (CBM) formation can be challenging because of the special properties of the formation itself and the specific treatment parameters. Based on experience gained working with dozens of monitored CBM treatments, several specific challenges and their solutions can be identified. Events created during such treatments are usually small in magnitude as a result of the often small injection rates and petrophysical properties of the target formation. To detect these small events over the ambient noise, the sensors have to be in relatively close proximity to the injection. In addition, it is important to reduce the ambient noise as much as possible. Because options to reduce ambient noise are limited, it is imperative to ensure that the sensors and casing are securely coupled to the surrounding rock. In some cases, it is better to place the sensors higher above the zone of interest if a better coupling can be achieved. Another common challenge in CBM formations is the high velocity contrast between the target formation and the surrounding rock, which creates some mathematical challenges in the accurate localization of the events. Extensive model calibration, accurate logs, and clear events in known locations (e.g., perforation shots) can improve the overall location accuracy significantly. Most of these issues can be addressed in prejob modeling studies that quantify viewing distances, location accuracy, and waveform appearance etc., before any microseismic data is acquired. These studies help anticipate potential challenges for particular projects as well as document realistic accuracy levels, which are essential for a comprehensive interpretation of the microseismic-event distribution.
Hydrate Formation Characteristics of Natural Gas During Transient Operation of a Flow Line
Authors: Lorenzo Mauricio Di , Kozielski Karen , Seo Yutaek , Soto Gerardo Sanchez , Zhang Junfang 
Published: February 2011

Abstract
Hydrate management during transient operation of subsea flow lines has been identified as one of the greatest challenges for deep water O&G production. Experiments using natural gas and de-ionized water were conducted in a laboratory flow loop (1" diameter and 40 m length) to investigate the dynamics of hydrate formation during simulated shut-in and restart conditions. Variables studied include different operational pressures and sub-coolings.
This work will provide valuable information for the establishment of cost-effective strategies to guarantee the continuous flow of fluids in subsea production systems, particularly during transient operations such as scheduled maintenance or unplanned shut-downs.
During the shut-in period hydrate appears to nucleate along the gas-water interface and grow as a film that spreads across the entire interface. At a pressure of 1,500 psi and sub-cooling of 15°C, dendrite crystals start to appear at the film and grow into the water phase until a thickness is reached where further grow stops. It is noted that, although hydrate is observed as a thin film during the shut-in period, most of the water is converted to hydrate upon restart. At every pressure condition evaluated in this study, slurry like hydrate flow has been observed upon restart, being flushed along the pipe-line by the gas flow.
Transient operations of subsea flow lines require strict adherence to operational procedures which include depressurization and flushing of the lines with thermodynamic hydrate inhibitors. The results of our work suggest that the blockage is more likely to occur during restart so operating procedures must be designed to minimize the risk of hydrate blockage based on specific factors such as driving force, water content, and gas flow rate. It is considered that the flow loop experiments could provide valuable insight into the dynamics of hydrate blockages formed under flow conditions in gas dominant flows.
A New Approach for the Realistic Evaluation of Very Thin Reservoirs of Krishna Godavari Basin, East Coast, India
Authors: Yadav Lalaji , Dutta Tanmoy , Kundu Ashish , Sinha Neeraj 
Published: February 2011

Abstract
In thin bedded reservoirs high resolution borehole images are generally used to determine distribution of high quality, productive sands. Deep water Tertiary reservoirs of Krishna Godavari basin are generally very complex and heterogeneous, ranging from massive thick sands to highly laminated very thin sand/shale sequences with average bed thicknesses less than the vertical resolution of microresistivity-imaging tool. The image tool responds to the beds and features smaller than the vertical resolution but can not accurately determine laminar bed thickness which can be used as an integral part of low- resolution technique. In the absence of a well defined set of thin bed boundaries from image tools, an integrated of approach of forward modeling and inversion is also impractical for the accurate thin bed evaluation.
A new approach of laminated shaly sand analysis is developed where laminar sand/shale estimation is based on generation of binary lithology on shale volume curve derived from micro-electrical resistivity. Formation beds as thin as the twice of the sampling interval can be generated through this technique in such a way that cumulative net sand fraction is restricted with integrated sand volume. Laminar shale volume from image tool calibrated to the LamCount core data has been considered to be the ground truth in the analysis. The volume of dispersed shale and the total and effective porosities of the laminar sand fraction are determined using a Thomas-Stieber volumetric approach. Water saturation is estimated from laminar sand-fraction resistivity derived from electrical anisotropy.
Application of the methodology leads to an improved accuracy of reserve estimates and productivity predictions. Entire procedure is illustrated with an example of completely cored reservoir section. Results indicate that low resistive laminated reservoirs with very high shale fractions can be highly productive with reservoir quality equivalent or some times even better than massive thick beds.