bluuebunny/crossref_metadata_2025_split huggingface dataset:
Surfactant Flooding in Challenging Conditions: Towards Hard Brines and High Temperatures
Authors: Tabary R. , Bazin B. , Douarche F. , Moreau P. , Oukhemanou-Destremaut F. 
Published: December 2013

Abstract
Surfactant flooding processes become challenging in hard brines and/or at high temperatures. When hard brine is used as surfactant make-up brine (injection brine), chemical adsorption is high using conventional injection strategies. This makes the overall process performance limited. High temperature (&gt;80°C) raises thermal stability issues with subsequent loss of effectiveness.
This paper illustrates recent progresses achieved in those difficult conditions. We show that good performances can be obtained by combining appropriate formulations with adapted injection strategies, i.e. slugs design, depending on reservoir conditions. A particular emphasis is set on solutions that can be applied in the field.
High performances solutions first rely on selecting appropriate surfactants and polymers from an extended portfolio of industrial products. We demonstrate that ultra-low interfacial tension formulations can be successfully designed for a wide range of conditions, i.e. from mild to difficult conditions, including very hard brines, very high salinities (&gt;200 g/L) and/or high temperatures (up to 120°C).
Various coreflood experiments are then reviewed to define guidelines to address challenging conditions:
Starting from mild conditions, i.e. soft brine at moderate temperature, we show that performance of surfactant flooding relies on the combination of properly designed chemical formulation and appropriate injection strategy. In soft brine, a salinity gradient is shown to provide high performance; In hard brines, surfactant adsorption is significantly higher than in soft brines. We demonstrate that a conventional salinity gradient injection strategy becomes ineffective when hardness is increased. Surfactant adsorption is drastically reduced (&lt;0.2 mg/g) when using appropriate adsorption inhibitors. This results in a very high oil recovery (~90 %ROIP) with performances comparable to the one achieved in soft brine conditions; For high temperatures (&gt;70–80°C), adapted protocols are required to address thermal stability issues and subsequent loss of performances. New surfactants, polymers and additives are available to address these conditions. Successful oil recovery experiments done up to 120°C are discussed.
The paper will demonstrate how surfactant flooding can be successfully applied in challenging reservoir conditions opening new opportunities for chemical EOR.
Liner Hangers Technology Advancement and Challenges
Authors: Mohamed Abdullah O. , Al-Zuraigi Ali 
Published: December 2013

Abstract
Ever since man began drilling for oil, operators have continuously looked for ways to increase drilling efficiency and reduce the cost of hydrocarbons recovery. As part of this search, the openhole casing technique was developed to prevent drilled holes from collapsing. Then, liner strings were introduced to the industry as an alternative for the long casing strings in production intervals.
Eventually, liner hangers were introduced. As time passed, they became a well-defined segment in the oilfield services business. Service companies employed technology to develop advanced liner hangers, beginning with mechanical-set liner hangers, and evolving through hydraulic-set liner hangers and balanced cylinder hangers to expandable-type liner hangers. Each hanger-setting mechanism mentioned here had its strengths, advantages and limitations. This made each type of setting mechanism optimally fit for a certain application, but perhaps not the best fit for other applications.
In this paper each setting mechanism will be assessed to show its strengths, advantages and also limitations and disadvantages. Our goal is to make decisions on liner hanger setting-mechanism selection more accurate and to give drilling engineers a better understanding of liner hanging techniques.
We will also review liner running techniques such as floating liners, drilling/reaming liners and steerable drilling liners to show each technique’s advantages and limitations. Case histories will be used to illustrate the different applications and liner hanger technical solutions available in the industry.
Practical Aspects of Multistage Fracturing from Geosciences and Drilling to Production: Challenges, Solutions and Performance
Authors: Al-Ghazal Mohammed , Al-Driweesh Saad , El-Mofty Wael 
Published: December 2013

Abstract
Open hole multistage (OHMS) fracturing completions were used in some Saudi Arabian carbonate and sandstone wells as early as 2007. Installations were limited in the early years, while benefits were being examined and analyzed. It was soon apparent that OHMS completed wells resulted in increased initial production and less departure from the theoretical hyperbolic decline curves. Accordingly, the number of OHMS installations is increasing steadily. Saudi Aramco is on track in 2013 to install 40+ OHMS systems – mostly in deep tight gas wells.
Installation of OHMS completions in Saudi Arabia wells had its own initial set of challenges; therefore, a proper learning curve had to be structured for operational and functional optimization as well as ultimate production enhancement. Very early installations faced deployment problems, mainly with differential sticking. This issue was addressed and mitigated using purpose-designed workflows. Moving forward, it became apparent that some wells were demonstrating symptoms of hydraulic communication between stages, which was a complex issue that required a sophisticated workflow. This included detailed studies of dominant stress profiles and changing the lateral azimuth to be drilled along the minimum horizontal in-situ stress plane. This clearly promoted transverse fractures and helped in minimizing longitudinal fractures that tend to propagate parallel to the borehole, thereby connecting two or more stages through the rock matrix and minimizing the overall efficiency of the intended fracturing operation.
This paper outlines the challenges encountered, reviews the risk mitigation process and details how the various issues were overcome. The paper also compares long-term production results from OHMS wells with non-OHMS wells, and explores other initiatives where OHMS systems can further improve well performance.
Novel Surveillance Technique for Beam-pumped Wells to Minimize Intervention and Optimize Production, South of Oman
Authors: Zreik Bassam , Shaibani Mahmood , Azzazi Mohamed , Guntupalli Suryanarayana 
Published: December 2013

Abstract
Majority of oil wells operated by Petroleum Development Oman (PDO) are produced by beam-pumps (BP). Average water cut in a number of fields in South of Oman reaches 95%. Increasing water production overloads processing facilities leading to handling and disposal constrains requiring wells to be shut-in.
BP completions are not surveillance friendly making production logging to identify water entry for optimization (water shut-off) a challenge. The current technique to acquire production logs requires recompletion to dual-string completion to allow logging: BP short-string and surveillance conduit long-string. This is resource intensive, high cost, restricts production and limited to 9-5/8in. cased wells. Moreover, new wells are completed with dual 9-5/8in. × 7in. casing for well life-cycle integrity management.
A novel solution was developed and part-funded by PDO consisting of a jet-pump (JP), 1in. inside 2in. concentric-coiled tubing (CCT) strings, power cable and production logging tools (PLT). This cost-effective real-time surveillance technique will facilitate routine production logging in BP wells, significantly reducing well intervention time and cost (50% reduction) as only the rod string is retrieved by light-hoist in preparation for logging.
Wells completed with dual-string completions, which have previously been production logged were selected for field trial. These existing logs were used as a baseline for new log comparison. The technique was successfully deployed in a 3 well field trial campaign for the first time in southern oilfields (industry first). The new production logs compared very well to existing logs (same water signature observed), proving the techniques robustness to identify water entry in different production environments.
We preset advantages of the new technique over conventional, candidate selection, logging tool options, interpretation methodology, field trial results and comparison logs. This new system is being deployed across PDO and is applicable to other fields being produced by BP, progressing-cavity pump (PCP) or electrical submersible pump (ESP) to identify water entry for production enhancement or reservoir monitoring.
ESP Surveillance and Optimization Solutions: Ensuring Best Performance and Optimum Value.
Authors: Al Maghlouth Abdulmonam , Cumings Matt , Al Awajy Majed , Amer Abdulrahman 
Published: December 2013

Abstract
One of the most common and cost effective secondary recovery techniques used in the industry is Electrical Submersible Pump (ESP). This technology uses the ability to pump very large volumes of fluid, by decreasing the bottom hole pressure allowing oil to flow from the reservoir and adding energy from the pump and electric motor to produce the fluid to surface.
Recent ESP designs are very effective "Intelligent" equipment enabling real-time monitoring of well performance. Failure to ensure ESP equipment operation within the recommended operating ranges could result in a premature loss of an ESP and significant increase in operating cost.
With dynamic and changing operating environments, it is essential to continuously monitor and diagnose ESP operating conditions, leveraging real time information received from the pump, to optimize its run life and avoid premature failures.
This paper will highlight the methodology used by Saudi Aramco to adopt a state-of-the art monitoring and diagnostics solution for ESP as well as the long term strategy for advance solutions. The ultimate objective is to increase ESP run life, lower operating cost, and maximize production.
Different layers will be discussed covering Saudi Aramco’ ESP surveillance and optimization approach including required infrastructure, monitoring factors, real time data requirements, basic and advanced diagnostic features associated with ESP monitoring.
First Evidence of Tunnel Valley-Like Formation During the Late Ordovician "Subgalacial" Period in Southern Tunisia Influence on the Jeffara Sandstone Reservoir Quality
Authors: Soua Mohamed 
Published: December 2013

Abstract
Through this last decade numerous wells have been drilled to the Ordovician in southern Tunisian Ghadames basin. They have met mudlog gas as well as mudlog oil shows in one or several sandstone levels. Some producing wells from the Silurian section display log pay in the Ordovician but seem to be off to the mapped Ordovician depth structural closure.
Alternatively, large 3D seismic survey has been undertaken in southern Tunisia in order to map the Ordovician. Isochore, isopachs and isobaths maps have been generated on four (04) main reservoir intervals all of which have produced from several fields in the Ghadames Basin (including Algeria and Libya). These reservoirs are (1) Jeffara, (2) Bir Ben Tartar, (3) Kasba Leguine and (4) Sanghar Formations (Tunisian nomenclature). In Southern Tunisia the Upper Jeffara sandstones, the Jeffara sandstones and the Bir Ben Tartar are classified as the primary reservoir intervals.
Generated isochore map of the upper Jeffara sandstones, has been used as evidence of a "geant" Tunnel valley shape in relationship with other valley structures pertaining to the Libyan side.
As the Ordovician sandstone reservoirs in Tunisia have poor reservoir quality but locally some intervals have tested condensate, some fields have proved that syn-glacial deposits form a gas reservoir (e.g. Tiguentourine field in south-eastern Algeria). Within such facies, the Ordovician has tested gas and/or condensate from a number of wells in the Ghadames basin.
This proposal will involve the existence of valley-fill sandstones pertaining to the Jeffara formation in southern Tunisia giving evidence of sub-glacial environment of deposition where iceproximal glaciofluvial deposits form the highest quality reservoirs using (1) isochore and isopachs maps of the Ordovician, (2) core analyses, (3) cyclostratigraaphy and (4) chemostratigraphy (major and trace elements). This will enhance the exploration activity for the Ordovician in southern Tunisia.
Innovative Ethane Liquefaction Process through Cryogenics
Authors: Al-Ghamdi Alsadat H. , Al-Faifi Yahya H. 
Published: December 2013

Abstract
Saudi Aramco’s Berri Gas Plant recognized that ethane liquefaction is achievable within the ethane and NGL recovery turbo-expander plant by installing a new brazed aluminum heat exchanger. The objective of this exchanger is to utilize the available cryogenic conditions from the cold de-methanizer overhead and liquefy part of the ethane product with no major impact to plant operations. This initiative eliminates the existing ethane liquefaction process and increases the liquefaction rate by 25%.
3D Basin and Petroleum Systems Remodeling of San Joaquin Basin, California
Authors: Abdelrahim Amgad A. , Primio Rolando di , Unnithan Vikram 
Published: December 2013

Abstract
California has long been one of the USA’s most important oil-producing states, and the San Joaquin Basin has long since eclipsed as the country primary oil production basin. San Joaquin Basin is also home to 21 giant oil fields that have produced over 100 million barrels of oil each, with four "super giants" that have produced over 1 billion barrels of oil. Among these "super giants" are Midway-Sunset (the largest oil field in the lower 49 United States), and Elk Hills (the former U.S. Naval Petroleum Reservoirs).
In 2007, the U.S. Geological Survey (USGS) published a complete assessment of the oil and gas resource potential of the San Joaquin Basin Province of California. With respect to technically recoverable undiscovered conventional hydrocarbon resources in the San Joaquin Basin Province, the USGS assessment team1 estimated means of 1.8 trillion cubic feet of gas (TCFG), 393 million barrels of oil (MMBO), and 86 million barrels of total natural gas liquids (MMBNGL) for five total petroleum systems (TPS), Winters-Domengine TPS, Eocene-Miocene Composite TPS, Eocene Composite TPS, Miocene TPS and Neogene Non-associated Gas TPS.
A 4-D Petroleum Systems Model was build and published by the USGS assessment team in 2007 (Used in this re-modelling project as base case model), but due to limited Rock-Eval/total organic carbon data, the Tumey formation was modelled using constant values of original total organic carbon and original hydrogen index (Values used by the modelling team were, 2% TOC and HI equal to 550 mg hydrocarbon/g total organic carbon). Maps of original total organic carbon and original hydrogen index were created for the other three source rocks.
In this re-modelling effort, 6 wells were found to have Rock-Eval data for Tumey Formation that would be suitable to create original total organic carbon and hydrogen index distribution maps for Tumey Formation. The maps were used in remodelling the San Joaquin Basin Petroleum systems and results for Tumey Formation were compared to the earlier results. Petrel®/PetroMod® Workflow was used for re-building the BPS model Heatflow was a challenging and important parameter for the model calibration. The 2007 published model results didn’t achieve the best vitrinite reflectance and temperature calibration with selected calibration wells. In this project, the published San Joaquin heatflow information by Colin Williams (Colin F. Williams’s presentation, USGS, Menlo Park, CA, 2008) was used to create new basin surface heatflow trends and maps used for re-modelling sensitivity and calibration runs.
It was found that lower surface heatflow values from what was applied during the 2003 assessment model gave better calibration with well data.
Managed Pressure Drilling Technique Applied in a Kurdistan Exploration Well
Authors: Driedger D. J. , Kelly S. P. , Leggett C. , Thain J. , Silva M. 
Published: December 2013

Abstract
Talisman Energy deployed MPD technology in their Kurdamir-2 exploration well using a fully automated managed pressure control system with a rotating control head, back-pressure pump, and MPD choke manifold. This technology enabled the control of the equivalent mud weight while drilling potential hydrocarbon zones. Utilizing a mass flow meter with real-time monitoring of mud weight allowed accurate observation of gains and losses. A constant bottom hole pressure technique was used to manage the annular pressure profile using the MPD choke to apply surface back-pressure. An auxiliary pump was used for continuous circulation across the top of the well during connections. The system was also used while cementing the liner to manipulate equivalent mud weight.
The fully automated MPD system was used while drilling various hole sections. This resulted in a mud program which allowed for a mud weight closer to the pore pressure. Additional backpressure was applied at surface during static conditions to compensate for frictional losses. Gas kicks were detected and safely circulated out by applying surface back pressure with the automatic choke manifold while maintaining penetration rates, improving safety, and reducing drilling cost by avoiding NPT. Accurate pore and fracture pressure was determined through hydraulic modeling and real-time monitoring of the well bore. While cementing the liner, the MPD system enabled Talisman to avoid changes to the mud system by raising the equivalent mud weight through manipulating surface back pressure.
The automated MPD system enabled Talisman Energy to drill to the target depth by controlling and manipulating the bottom hole pressure through multiple abnormal pressure zones within the open wellbore. The system ultimately enabled early detection of influxes and losses, dynamic equivalent mud weight management, maintenance of BHP during static conditions, dynamic LOT’s and FIT’s, formation strengthening, and cementing the liner without losses.
Integrated Drilling, Geosteering & Fluid Engineering Practices in Order to Maintain Horizontal Wellbore Stability & Maximize Reservoir Contact in a Channel Sand Reservoir
Authors: Fernandes Warren , Jadhav Prakash , Zaki Mohamed Moamen , Dutta Bikramjit 
Published: December 2013

Abstract
Integrated Drilling, Geosteering & Fluid Engineering Practices in order to maintain horizontal wellbore stability & maximize reservoir contact in a Channel Sand Reservoir.
The target sand belongs to a transgressive facies and is characterised by channel levee system. Distribution of facies varies with the migration of channel system, making it a real challenge to place a horizontal well bore along particular target sand. While placing the lateral, structural dip and distribution pattern of channel were considered to optimize the inclination of horizontal as well as its azimuth for maximizing the contact area along the target sand.
This paper discusses the use of appropriate drilling, geosteering & fluid technology & engineering practices in order to deliver stable horizontal well bores and maximize reservoir contact so as to improve production & recovery in this depositional environment.
From a drilling perspective, use of rotary steerable tools with the non rotating sleeves and a compatible bit provides minimal damage to the formation. Steering is almost totally independent of stick-slip dynamics because the ribs do not rotate. The short length & retractability of this non rotating sleeve reduces differential sticking and hanging risk. The result is a highest quality borehole, virtually free of ledges, undulations and micro-tortuosity.
For geosteering, in addition to the conventional triple combo logging suite, use of azimuthal resistivity with signal strength, direction and distance to bed capability enable proactive geosteering in order to predict and avoid approaching reservoir boundaries. Realtime density imaging helped to further fine tune the wellbore positioning in the sweet spot of the reservoir and also for stratigraphic position determination through correlation & dip picking.
The mud system was engineered to strengthen the wellbore and improve its stability using revolutionary bridging technology while drilling. Subsequently to remediate near well bore damage & improve producibility, Mesophase technology was incorporated.
The result of this integrated drilling, geosteering & mud engineering approach was successful delivery of clean, stable horizontal wellbores. Since the wellbores was placed optimally in the higher regimes of the reservoir and completed using ICDs, better ultimate recovery can be expected.
Removal of Organic Deposits from Oil Producing Wells in a Sandstone Reservoir: A Lab Study and a Case History
Authors: Al-Taq Ali A. , Zeid Saleh M. , Al-Haji Habeeb H. , Saleem Jaffar A. 
Published: December 2013

Abstract
Organic deposit including asphaltene and paraffin may damage the near wellbore area and obstruct production tubings resulting in partial or total loss of well productivity. Most of asphaltene deposits are associated with paraffin. This paper presents a first successful field application of a lab proven/optimized chemical solvent to remove organic deposits from a dead oil well in a sandstone reservoir.
A vertical gravel-packed oil producer well was dead due to deposition of organic material in 3 ½" production tubing forming obstruction to flow. The deposition is expected to take place due to long shut-in time as experienced in this well with high GOR. A bailer samples was obtained from this well. Analysis of the obstructing material indicated that they were mainly asphaltene associated with paraffin. Solubility of obtained organic deposits in several solvents was evaluated at reservoir temperature (188°F) and monitored as a function of soaking time.
Several criteria were considered in selecting of the optimal solvent formulation, among which were safety and solvency power. The selected formulation incorporates asphaltene dissolver solvent and paraffin dissolver solvent in addition to surfactant. Application of the optimal solvent formulation, that exhibited the maximum solvency power in a minimum soaking time, was very effective in restoring well productivity while minimizing operational cost. A total of 12 feet of obstructing organic deposits were removed from the production tubing using coiled tubing in a multi-stage treatment. Following, the solvent was squeezed into the formation across the screens to maximize cleaning efficiency at the source. The sustainable oil production rate obtained and asphaltene content in flow back samples indicated that the treatment was very successful. To prevent further asphaltene/paraffin precipitation during shut-in time, asphaltene/paraffin inhibitor is recommended. A detail of asphaltene/paraffin formation mechanism, lab evaluation and field application results will be addressed.