bluuebunny/crossref_metadata_2025 huggingface dataset:
Reservoir Connectivity Evaluation and Upscaled Model Screening Using Streamline Simulation
Authors: Fanjul Javier Prieto , Vicente Mario Gustavo
Published: December 2013

Significant gas potential has been identified in both conventional and unconventional reservoirs in emerging gas projects in Algeria, south-western Sahara. This study is focused on Lower Devonian reservoirs, which overall depositional model is characterized by shallow marine shelfal to tidal sandstones and mudstones in a range of depositional settings, with thin thickness (less than 10 m) and low porosity and permeability, at 3000–4000 m depth. The analysis of eight exploratory wells drilled in the area, has shown that the field under study presents high lateral and vertical heterogeneity, with an important connectivity uncertainty.

Geological models were performed with the objective to evaluate the structural complexity and high reservoir heterogeneity. In order to account for the properties variation uncertainty in the inter-well distribution, and the impact in upscaled models and resulting reservoir simulation, different geological model approaches were evaluated using streamline simulation, concentrating the study on some of the most important parameters that control the number of wells and recovery: reservoir quality, distribution and connectivity.

Streamline simulation allowed us to optimize the simulation grid, with the objective to capture the critical reservoir features of the fine-grid geological model. Streamline simulation can be used to analyze and rank different geological models based on certain dynamic performance parameters that effectively reflect the reservoir connectivity, which cannot be easily analyzed with finite difference simulations. The volumetric sweep efficiency and the water cut response can be used to understand the reservoir connection and heterogeneity, and the optimum level of upscaling comparing with fine-grid models.

Relatively few real field case examples of this technique have been documented in the past and this paper presents a clear workflow which helped to improve the knowledge of upscaled models screening and resulting reservoir connectivity evaluation.
Pressure Changes Effects of the Outlet Free Water Knock Out on the Oil in Water: a Case Study for Karakus Field, Adiyaman - Turkey
Authors: Ergun Ender
Published: December 2013

Over the past few decades, oil recovery is becoming a more significant issue. Not only in reservoirs but also in surface equipment, the loss of oil has to be degraded owing to its value. Especially, in Karakus Field, Turkey, throughout a year, more than 6,000 bbl oil is lost from just free water knock out (FWKO) which is a strikingly challenge which has to be dealt with.

Technically, due to stability of microemulsion for oil in water, the loss of oil occurs. In terms of increasing operating pressure of FWKO, entropy decreases. Thus, increments of Gibbs free energy can be supplied. Consequently, by breaking the stability of microemulsion, better quality separation can be obtained in disposal water.

This study explained that oil loss from outlet of the FWKO was attenuated by increasing pressure of vessel, while other parameters were steady such as temperature, inlet and outlet flow rate and etc. in Karakus Field. By 50 psi gradually increment of vessel pressure from 100 psi to 300 psi, quantity of oil in water from outlet of the vessel was observed at 4,300 and 6,200 bbl/day disposal water rates. By augmenting the pressure of knock out, oil in disposal water which was conveyed to injection wells reduces dramatically. According to experimental results, a significant relation as exponentially between pressure and oil in water was found. Briefly, 900 and 1,500 bbl of oil can be saved annually in order with two disposal water rates.
Dual Lateral Open Hole Coiled Tubing Acid Stimulation in Deep HPHT Sour Gas Producer Wells — Field Experience and Lessons Learned from the Ghawar Field
Authors: Al-Zaid Mustafa R. , Al-Ghazal Mohammed A. , Al-Driweesh Saad , Al-Ghurairi Fadel , Vielma Jose , Chacon Alejandro , Noguera Jose
Published: December 2013

In recent years, high-pressure/high temperature (HPHT) sour gas producers in Saudi Arabia, completed with two or more open hole laterals have faced several operational challenges, specifically for well intervention and stimulation procedures. Several lessons learned throughout the timeline of the operations and the procedures have evolved to optimize and enhance the results. Drilling and completing open hole multilateral gas wells in carbonate reservoirs is a common practice in Saudi Arabia to maximize reservoir contact and increase the recovery of reserves. The majority of these wells require coiled tubing (CT) conveyed acid stimulations to remove drilling damage and enhance productivity after the drilling process.

The challenging conditions encountered during the aforementioned CT interventions include: extended open hole horizontal sections with large hole diameters affecting the ability of reaching the deepest zones of interest; pumping 26% inhibited hydrochloric (HCl) acid for extended periods of time at high temperature with extremely high H2S and CO2 content, generating a very corrosive environment for all tubulars involved in the operation; wellbore instability issues inducing obstructions that prevent the accessibility to open hole sections; accessibility of alternate laterals, especially after the first lateral has been stimulated; optimum rate and pressure to achieve the desired pressure drop across hydrajetting nozzles; and natural fractured reservoirs that promote fluid losses affecting the optimum fluid placement control.

The inclusion of friction reducers for CT extended reach applications, combined with the introduction of larger outer diameter (OD) CT, have improved the access to the zones of interest. The redesign of the isolation sleeve for the jetting tool has reduced the number of required trips when obstructions have been encountered, including the improved use of steering tools to access target laterals. Further laboratory analysis, specific to the HPHT sour conditions of these wells, has been performed to minimize corrosion in the completion and the CT, and to optimize the pumping schedules to target the pay zone. This paper provides details about field experiences and lessons learned with this type of stimulation, and describes challenges faced and the engineering solutions developed to overcome them.
The Impact of LoSal™ on Oil Recovery from a Selected Carbonate Reservoir in Abu Dhabi-An Experimental Approach
Authors: Al-Attar H. H. , Mahmoud M. Y. , Zekri A. Y. , Almehaideb R. , Ghannam M. T.
Published: December 2013

Low-salinity water flooding LoSal™ has been used to improve oil recovery for many decades. Historically, the physical mechanism behind this improvement in oil recovery was attributed to the pressure maintenance and displacement of oil by injected water. Recently, evidence from laboratory and field tests indicated that water flooding also involves chemical processes and that modifying of the injection brine salinity and its ionic composition can significantly impact the oil recovery. Several theories regarding the mechanism of LoSal™ flooding have been discussed in the literature. These include interfacial tension reduction, wettability alteration (cation exchange), change in pH (increase), emulsion formation, and clay migration. There is no agreement, however, among the researchers regarding the mechanism of LoSal™ flooding and although limited work has been done on carbonates, some studies have concluded that LoSal™ have no effect on oil recovery.

This work presents the results of flooding tests on selected carbonate core samples taken from Bu Hasa field in Abu Dhabi using sea water and two field injection waters, Um-Eradhuma (UER) at 197,584 ppm and Simsima (SIM) at 224,987 ppm. These results were used to evaluate the effects of brine salinity and ionic composition on the possible interactions of limestone rock/ brine/ and oil system and to identify the oil recovery mechanism. The field injection waters were diluted to salinities of 5000 and 1000 ppm and the optimum salinity was determined and then modified by varying the sulfate and calcium ion concentrations. Wettability alteration was determined by contact angle measurements. Interfacial tension measurements of the studied systems were also performed in an attempt to evaluate the flow mechanism with LoSal™ flooding.

The experimental results revealed that a significant improvement in the oil recovery can be achieved through alteration of the injection water salinity. Reducing the salinity of UER water from 197,362 ppm to 5000 ppm resulted in an improvement of oil recovery from 63% to 84.5% of OOIP and the latter salinity was used to evaluate the impact of changing the sulfate and calcium ion concentrations on oil recovery. Results also indicated that sulfate concentration has a significant effect on the flooding process and that increasing the sulfate concentration beyond some optimum concentration of 47 ppm resulted in a negative effect on the flooding process. Contact angle measurements indicated that lowering the solution salinity could shift the wettability of the system towards intermediate wettability levels and that the UER water exhibits higher shift toward intermediate wettability compared to other waters. Results also indicated that there is no clear correlation between the improvements in oil recovery and interfacial tension and the pH of the studied systems.
Strategic Scope of Alternative Optimization Methods in History Matching and Prediction Workflows
Authors: Schulze-Riegert R. , Chataigner F. , Kueck N. , Pajonk O. , Baffoe J. , Ajala I. , Awofodu D. , Almuallim H.
Published: December 2013

Reservoir simulation workflows from history to prediction are built on a number of alternative optimization and sampling techniques with different characteristics. Adjoint techniques derive analytical sensitivities directly from the flow equations of the simulator. In a model update step those sensitivities are used for property modifications on grid cell level. Derivative-free optimization techniques like evolutionary algorithms are flexible and deliver alternative history matched cases. The propagation of reservoir uncertainties from history to prediction is often investigated using ensemble-based approaches. Markov Chain Monte Carlo and EnKF techniques are applied to generate an approximate posterior distribution as a basis for estimating prediction uncertainties.

In this work we investigate alternative optimization, sampling and data assimilation techniques with application to history matching workflows within one application framework for comparison. Validated simulation models are used for production forecast and field development planning. Methods are investigated with a focus on history matching efficiency, flexibility to integrate different types of model parameters, integration option for static and dynamic modeling workflows, capability of supporting uncertainty quantification workflows for estimating prediction uncertainties and the ability to leverage on distributed computing.

Optimization workflows are applied to a reasonably complex benchmark problem for comparison. Well production data is used in the model calibration phase and history matched simulation models are carried forward to prediction. The impact of alternative optimization concepts on estimating prediction uncertainties is discussed. This work gives an overview on alternative optimization concepts and relates capabilities, strengths and weaknesses. The impact of workflow choices on estimating prediction uncertainties is discussed. Practical conclusions are drawn for real field applications scenarios.
Rejuvenating a Mature Transition Zone Carbonate Waterflood Through Subsurface – Surface Integration: the Value of Combining Improved Subsurface Understanding While Managing Aging Facilities (Shuaiba, Sultanate of Oman)
Authors: van Koolwijk M. E. , Ghufaili A. , Warrlich G. , Goossens P. , Harris J. M. , Ogawa M. , Adhoobi A. , Hajri M. , Armstrong H.
Published: December 2013

This paper describes how after a period of no activity, a waterflood development is rejuvenated. This is achieved through full integration from geosciences, reservoir engineering and drilling to facilities engineering, operations and surveillance. This collaboration enabled further development following improved subsurface understanding based on appraisal, surveillance and production data as well as managing integrity and capacity issues of the aging facilities.

The Shuaiba limestone reservoir is situated in a fault-bounded, north-south trending anticline. The reservoir (~26% porosity with low matrix permeability, 1–20 mD) contains light oil (~35 API) in thin column heights of typically 5 to 30 m.

In the initial development phase the reservoir was developed by multilateral horizontal producers. Field-wide water injection started ~10 years after initial production with horizontal water injectors placed in multi-lateral patterns of up to 7 legs. The complexity is not limited to the subsurface; surface facilities handle oil-water separation from deeper reservoirs as well as 7 satellite fields.

After years without drilling activity, appraisal wells were recently drilled outside the field extent to test both structural and saturation models with the FWL progressively deepening towards the flanks by approximately ~5m tvd per km. This has added the opportunity of new flank developments to the existing field with significantly increased reserves. New insights into mobile saturation have driven the production threshold down to as low as 25% oil saturation.

The flanks will be developed with single lateral wells, taking into account the thin oil column and optimizing surveillance opportunities.

Challenges facing this development are related to maintaining the aging facilities, integrated management of flow line replacements, overall production capacity and water injection constraints. These are tackled in an integrated manner through (1) debottlenecking the main station and reducing flow line length through remote manifold stations, (2) prioritized flow line replacements ranked by surveillance activities, (3) rejuvenating the water disposal system and (4) restoring the overall downhole injectivity. These combined efforts will expand production far into the next decade.
Effect of Water Fraction on Surfactant-Stabilized Water-in-Oil Emulsion Flow Characteristics
Authors: Al-Yaari M. , Hussein I. , Al-Sarkhi A. , Abbad M. , Chang F. , Abu-Sharkh B.
Published: December 2013

High friction losses while pumping emulsified acid in a carbonate stimulation treatment limit the injection rate, which can negatively impact operational efficiency; consequently, reducing friction is highly desirable. This study experimentally investigates the role of dispersed phase (water) fraction on frictional drag in different pipe diameters.

Flow loop experiments were conducted to study the effect of water fraction on the flow characteristics of surfactant-stabilized water-in-oil emulsions. Emulsion physical properties such as stability, type, and rheology measurements were correlated to pressure drop measurements in a flow loop consisting of 1-in and 0.5-in horizontal pipe diameters at constant (ambient) emulsion temperature.

The results demonstrated a shear thinning behavior for the emulsions being investigated. In addition, as water fraction increased emulsion stability increased. Furthermore, a significant reduction in emulsion viscosity and pressure drop with decreasing water fraction was observed. In one case, a decrease of water volume fraction from 0.7 to 0.6 resulted in a 60 to 75% drag reduction, depending on the Reynolds number (Re). Moreover, for a given water fraction, the reduction in drag of stable water-in-oil emulsions was found to be more pronounced in smaller pipe diameter due to the shear thinning effect and became significant at higher values of water fraction and Re.
Assessing Offshore Multilateral Well Potential from the Early Life of the Well
Authors: Zorbalas K. I. , Al-Yateem K. S. , Al-Muailu H. A.
Published: December 2013

Operators are continuously striving to improve oil and gas field development strategies. One of the major improvements in field development strategies is enhancement of well completion designs that maximize profitability while maintaining high standards of reservoir management. Completion strategies have been transforming over the years from conventional wells to the recently drilled multilateral (ML) wells and smart wells that combine inflow control devices (ICDs) and electrical submersible pump (ESP) equipment. The new era of intelligent wells is focused on over-performing the old completion practices in terms of well productivity and reservoir sweep efficiency.

Well-A was trial tested for the first time in an offshore field by deploying a hydraulic line wet mate (HLWM) connect system with the intelligent completion (IC). This tool allows de-completing the upper completion, which includes an encapsulated (pod) ESP portion, without the need to de-complete the lower intelligent completion. The completion operation of this well consists of two stages: the first stage consists of completing the well with the intelligent completion, HLWM connect tool and a production packer. The second stage is performed by pulling the production packer by disconnecting at the HLWM point and consequently running the ESP completion while maintaining the integrity of the lower intelligent well completion in place. The completion operation in Well-A was run in two stages only to trial test the reliability of the HLWM connect system in this field, since it was utilized for the first time. In subsequent wells, the intelligent completion can be run in one stage with the ESP integrated as part of the final completion design.

A production optimization sequence utilizing a simulation model was used to analyze the potential of the well and selecting the right inflow control valve (ICV) settings from the two laterals for optimum reservoir drainage.
Detecting Changes in Permeability from Seismic Data
Authors: Wiley Robert , Wilson Peter , Peters Scott
Published: December 2013

Carcione and Picotti (2006) modeled the partially saturated rock case as alternating layers of gas charged permeable rocks with water charged permeable rocks and predicted there would be a velocity variation in the permeable layer versus frequency – within the seismic bandwidth. We show how these variations change with permeability. We then extend this to show variations in the reflected seismic wavelet. Finally we will demonstrate how modern Spectral Decomposition techniques can be used identify these permeability induced wave shape variations. We would point out that we are working with effective permeability which for a layer with gas will be much higher than the intrinsic permeability of a brine-filled rock.
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

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 (>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 (>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 (<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 (>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

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

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

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

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

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

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

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

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

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

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.
Case History: Innovative Milling Operation of Stuck Wellhead Tubing Master Valve using Coiled Tubing at South Ghawar Field, Saudi Arabia
Authors: Al-Buhassan Shaker , Zefzafy Ibrahim , Al-Shehri Ayedh , Al-Mukhaitah Abdulaziz , Thawaiqib Abdulaziz
Published: December 2013

Milling a stuck partially opened wellhead tubing master valve (TMV) becomes inevitable to access the wellbore if all repairing attempts had failed. Typically, the milling can be accomplished by utilizing a milling machine, mounted on a wellhead, equipped with motors and special mills. In this case history, CT was selected to fully satisfy standard well control requirements. Different sizes of mills were utilized to provide access through the double disc gate valve to facilitate setting downhole barriers to replace the defective TMV with a new one safely and successfully. The post-job visual inspection of the milled bore showed regular cut of this gate valve. This paper highlights the extensive planning and preparation work performed to execute the job safely and successfully. The paper will also focus on the thorough risk assessment procedure and contingency plans to ensure all well control requirements are fully covered. This unique operation has showed that milling TMV using CT is proved to be a viable option addressing well control issues while performing the milling operation. The paper will also present many lessons learned to be applied in future similar jobs.
Petrel Workflow for Adjusting Geomodel Properties for Simulation
Authors: Hoffman David R.
Published: December 2013

During the initialization phase of a simulation modeling project, one of the most critical problems to overcome is the inevitable disconnect between the geomodel properties and reservoir performance in completion intervals. These disconnects can be the result of incorrect perforations, simple data errors, and/or poor reservoir characteristics. Poor reservoir characteristics, in turn, can be the result of sparse or clustered well control, erroneous petrophysical interpretations, or improper model property distribution. A simple Petrel-based workflow is described which can be used to automatically modify geomodel properties in model cells associated with completion intervals. Using the modified model properties, the numerical simulation model can be initialized and the simulation engineer can work on other early-modeling issues, while the modified property can be used to isolate property modeling errors for further evaluation and correction in the geomodel.

The workflow makes the basic assumption that if an interval has been perforated at any time in the well history, then that portion of the reservoir is assumed to meet minimum reservoir criteria for pay. Using the historical well events, a pseudo-log is created and used to generate a Petrel model property. This property is then used to evaluate and/or modify reservoir properties in completion zones. If a completed zone has reservoir properties which do not meet pay cut-off criteria, that interval is modified by the workflow so that it passes the pay cut-off without changing other parts of the geomodel. In the Awali Field model tested, the modified cells constituted less than 1% of the total model volume and the modified geomodel eliminates "non-connection" errors in the simulation model (however, the reservoir quality issues still exist). Using property filters, the modified cells can then be used to by the geomodeler to isolate the problem areas of the model for further evaluation and correction. Although this methodology is presented using Petrel as the geomodeling platform, the same approach could be easily adapted to most geocellular modeling applications.
Systematic Approach to Integrate a Comprehensive Surface and Subsurface Well Integrity Management System
Authors: Al Muailu H. A. , Al Syed S. , Al Omairen K. , Al Yateem K.
Published: December 2013

Proactive well integrity up-keep is an important health, safety, security and environment (HSSE) factor in the industry. Any lapse in well integrity can cause unintentional leaks, which can result in well control situation in terms of safety. This could also lead to acquifer contamination, which is a health and environmental concern. As both subsurface and surface are continuously exposed to deteriorating conditions associated with producing corrosive subterranean fluids from the well and the increasing age of wellstock, the possibility of incidents increases with time. At this point, developing a reliability management system of existing wellbores and wellheads is crucial to ensure optimum HSSE compliance. The objective of such a system is to optimize productivity and add value, by enlisting the causes and the available tools and methods against given well conditions, to ultimately extend the life of the wells, reduce HSSE concerns while reducing operating costs associated with post incident rectification, cleanup and improve reliability.

This paper presents an integrated approach that Saudi Aramco employed to address surface and subsurface well integrity by the incorporation of these types of management systems. In this approach, subsurface integrity issues are addressed through careful well design, continuous monitoring, and re-use of existing wellbores. This approach also provides a wider investigation of surface assets by revealing solutions to surface integrity problems, including unsecured wellheads, leaking wellheads and Christmas trees and limitation of offshore platform design.

To provide a broader insight of well integrity, this paper also focuses on the operational and well intervention phases of a well's life, and discusses evolution of the well integrity management system. The data management processes used to monitor the well integrity system is also discussed.