bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Field Application of a Permanent Fiberoptic Wellbore Fluid Level Monitoring System
Authors: Staveley C. , Doyle C. , Coetzee C. , Franzen A. , Boer H. Den , Rooyen A. van , Birch W. , Biderkab A. B. , Moes E. 
Published: November 2017

Abstract
To efficiently produce an oil rim and not the overlying gas cap or the aquifer below, it is important to be able to monitor the oil rim position. In highly fractured carbonate reservoirs the conventional method of monitoring oil rim movement is by periodically running wireline gradio surveys. However, some operators have found this method to be inconclusive and unable to provide information in a sufficiently timely manner to influence operations as the gradio surveys are only run a few times a year. We describe a project to design, field trial and qualify an alternative solution for real-time monitoring of the oil rim in carbonate reservoirs which overcomes these disadvantages.
Efficient Scheme for Native Carbon Dioxide Recovery from Sulphur Recovery Unit Tail Gas
Authors: Bonnereau Julie , Weiss Claire , Delannoy France , Linicus Matthias , Jüngst Eckhard , Terrien Paul 
Published: November 2017

Abstract
Oil and Gas operators are more and more interested in developing and improving native CO2 recovery technologies as capturing native CO2 can drastically reduce the greenhouse gases emission and at the same time can be valorized for enhanced oil recovery.
While considering CO2 emission from a gas plant, native CO2 significantly contributes to the total amount.
Usually when natural gas contains both CO2 and H2S, they are removed together and sent to an air fueled Sulfur Recovery Unit (SRU) resulting in a tail gas containing mainly nitrogen and CO2. The native CO2 can then be separated by the use of a chemical solvent such as Monoethanolamine (MEA) for example.
TOTAL and Air Liquide Engineering & Construction have developed and patented an innovative process scheme for recovering the native CO2 and reducing the overall operating and investment costs of such process.
This patented innovative process scheme consists in a Claus unit, fed with pure oxygen or enriched air instead of air, which leads to a tail gas stream containing mainly CO2 and H2 but no or only little nitrogen. A CO2 purification unit allows a CO2 rich stream to be recovered with a purity level reaching even 99.9%, while producing valuable by-products such as pure nitrogen and a hydrogen-rich stream, both of which can be used as utilities in other process units depending upon selected technology. This also reduces continuous emissions from the gas plant by eliminating the continuous operation of an incineration system.
The CO2 purification unit can be either membrane, cryogenic or adsorption technologies. This paper also discusses the integration of the technologies of Air Liquide Engineering & Construction: OxyClausTM, Tail Gas Treatment Unit (TGTU) and CryoCapTM, a very efficient CO2 purification technology.
The scheme has been studied in detail for specific application to optimize the overall integration. It has been also compared to conventional CO2 capture schemes.
Gas Tight Production Casing Remediation via Expandable Steel Patches
Authors: Szary Tomasz , Newton Daniel , Riou Yoann , Echasseriau Benoît 
Published: November 2017

Abstract
A major operator in the Middle-East faced a casing integrity issue on a well drilled in 2015, due to several leaking production casing connections determined through analysis of a number of data sets including pressure test results, casing connection torque turn charts and caliper logs.
Potential remedial solutions were limited to those that did not involve directly remediating the production casing as the number of suspect connections made these solutions high risk. Potential solutions were also required to meet a V0 "gas-tight" pressure integrity requirement to meet the need for gas lift production as well as provide a post remedial ID suitable to deploy the upper completion equipment through. Lastly, any solution identified was to have a high probability of success through existing qualification testing and field deployments.
The solution identified and selected was an expandable tubular technology called "Expandable Steel Patch", deployed with a deformable element hydraulically inflated, called "Inflatable Packer". When pumped from surface into this high-pressure balloon, the outer diameter increases, applying a force inside a steel pipe. This pipe, the Expandable Steel Patch, is pushed against the casing and stressed above the material plastic limit. The deformation is permanent. An outer skin of elastomer creates both a gas tight seal and anchoring in order to lock the patch in place and restore the integrity of the covered section. The final expanded ID of the patch is sufficiently large to allow standard upper completion equipment to be deployed through the patch.
This paper will highlight the application limitations that had to be met, the solution selection process and the operational deployment of a record five expandable patches in a single wellbore. Deployment results and technology experience will be reviewed.
Chemical Water Shutoff Pilot in a Mature Offshore Carbonate field
Authors: Cottin Christophe , Al-Amrie Omar , Barrois Emmanuel , Templier Arnaud , Salehi Nazanine , Zaitoun Alain 
Published: November 2017

Abstract
Total has been operating oil and gas production from a series of heterogeneous carbonate reservoirs offshore Abu Dhabi since 1974. New technologies to increase oil recovery have been always tested and deployed on this field as tertiary gas injection since the 1990's or chemical EOR with a surfactant polymer pilot recently. On the same dynamic, we tested chemical water shut off treatment on two highly waterflooded wells with the injection of relative permeability modifiers (microgels).
This paper describes the full workflow followed for the pilot implementation and lessons learnt.
A particularity of this field is to produce in commingle oil from different thin reservoirs, with permeabilities ranging from to 0.5 to 50mD. Well production is combined through a single sliding sleeve, thus any mechanical shut off is impossible to block the water coming from the high permeability zones that is why the injection of RPM was considered.
Microgels were preferred over conventional polymers gels due to their higher resistance to salinity, shear, and H2S.
Laboratory studies were conducted to select the best microgel size and to obtain inputs for near well-bore model simulation (microgel adsorption, permeability reduction, injectivity). Numerical simulations were performed to predict the well responses and to define the optimal slug injection.
For this first pilot using microgels in high salinity environment, two vertical wells producing from two different reservoirs were tested, with watercut of 92 and 97%.
The microgel fluids were bullheaded into the whole perforated interval, the fluids were prepared on a nearby marine vessel; the operational challenges faced are detailed.
Preliminary results and way forward are described. The application of this microgel technology to high salinity and moderate temperature carbonate fields has a great potential to improve recovery in very mature fields at low cost.
Implementation of High Resolution Diagenetic Features into the Static and Dynamic Reservoir Models of a Giant Offshore Oil Field, Abu Dhabi
Authors: Shekhar Ravi , Naqbi Amna Al , Obeta Chukwudi , Ottinger Gary , Herrmann Rolf , Obara Tomohiro , Almazrouei Shamsa J. , Maqrami Zinab N. , Neyadi Abdulla Al , Edwards Ewart , Shebl Hesham , Li Dachang , Shehhi Budoor Hasan , Fazal Ayub 
Published: November 2017

Abstract
Lower Cretaceous-aged carbonate sediments in a supergiant Middle Eastern oil field are characterized by extensive diagenetic overprints (e.g., dolomitized burrows, dissolution fabrics and fractures) which occur over areas of several kilometers. Due to the permeability contrast with respect to surrounding fine-grained matrix, the diagenetic features are believed to play an important role in reservoir fluid-flow, particularly as a major contributor to early water breakthrough observed in the field. Uncertainties associated with three-dimensional subsurface reservoir models can be mitigated by incorporating the results of detailed reservoir characterization studies. How these study findings are successfully and meaningfully implemented into the reservoir model can be a challenge and requires an integrated effort by reservoir geologists, modelers, and engineers.
This paper discusses a comprehensive reservoir characterization and modeling study conducted to capture the impact of diagenetic features on reservoir flow properties. A novel method was developed to map the spatial and stratigraphic distribution of these features from cores. Dolomitized burrows generally appear in core as randomly oriented features on a scale of cm to 10's of cm. They are characterized by grainier fill (packstone or grainstone), often dolomitized, within a background of muddier sediment (wackestone to packstone). Dissolution vugs are associated with algal rock type and can vary from few cms to 10's of cm. Fractures are generally layer specific and occur at the reservoir-dense boundaries. The origin of diagenetic processes and prediction of their occurrence is very difficult. However, the difference in texture and associated pore characteristics lead to heterogeneous porosity and permeability regimes that can have significant impact on sweep efficiency and recovery in oil fields that are subjected to waterflood.
A simplified, fit-for-purpose, rapidly updateable static model has been developed to ensure accurate stratigraphic and lateral distribution of diagenetic features based on cores, logs and dynamic data. Whole core data revealed potential guidance for assigning permeability in diagenetic features. A consistent SCAL framework has been developed to capture the relative effects of these diagenetic features on flow. After incorporation in the model, simulation results clearly shows water movement through these features and rapid water cut. This is in agreement to the field observation that has experienced earlier than expected water breakthrough and steady increases in water cut over time.
High-Resolution Sequence Stratigraphy Analysis and Diagenesis Evolution of a Barremian Carbonate Platform Kharaib Formation, Onshore Abu Dhabi
Authors: Torres Kevin Michael , Ugonoh Mohammed Salawu , Al Hashmi Noor Faisal 
Published: November 2017

Abstract
The aim of this study is to propose a stratigraphic and sedimentary framework though the integration of available sedimentary, diagenetic and petrophysical data, which will be utilized in the construction of a high resolution stratigraphic framework, as an input into comprehensive review and update of an existing model of heterogeneous carbonate reservoir in a mature field in Abu Dhabi, UAE.
Depositional facies have been defined in cored wells, subsequently were associated taking into account the biologic and sedimentary processes in response of carbonate growing and sea level changes, allowing the identification of the main stratigraphic surfaces.
Surfaces can extend the correlation along the field and define the model of facies that, with the evidence provided by cores, can recreate and predict the different regressive-transgressive cycles in high resolution which the carbonate platform were undergone during its evolution.
Diagenetic evolution, interpreted through laboratory observations, was integrated with facies and petrophysical evaluation allowing the understanding of the spatial distribution of petrophysical properties within a heterogeneous reservoir and define a new set of facies which will be used in the generation of geological static model.
Application of sequence stratigraphy methods in cores, and extended in logs allowed the identification of six depositional sequences, with thicknesses of 2 to 4 meters each, corresponding to the phases of carbonate platform growth. Within each depositional sequences, typical cycles were defined that support the understanding in the association of facies and their relationship during the deposition.
The identification of sedimentological cycles not only genetically organizes the facies and predicts the stacking pattern, but also makes possible to find an excellent correspondence between cycles from lowstand system track intervals with good to excellent permeability values, and cycles from transgressive system track intervals with low permeabilities.
Many of the sequence stratigraphy published articles driven for the most important reservoirs along the Arabian Plate, provide an excellent tool in the regional correlation. However, they are not enough to be used in the reservoir characterization in detail that is required during the development of the field neither as input data in the generation of geological static models that use the sedimentary trends as constrain to populate the petrophysical properties.
Maximizing Production Performance in an Undeveloped Reservoir: A Case Study, Offshore Abu Dhabi
Authors: Al-Hassani Sultan Dahi , AL-Tameemi Ibrahim Mohamed , Khan Owais Ameer , Ahmed Shafiq Naseem , Keshta Osama , Chaudhry Mohamed Zubair , Fares Wael , Essam Ramy , Abdulkarim Anar , Aki Ahmet 
Published: November 2017

Abstract
The value of the continuing integration of logging-while-drilling (LWD) and directional drilling processes has been more prominent in the current economic environment in terms of optimizing field development costs by means of precise well placement, as well as improved reservoir characterization and drilling performance in real time. A successful horizontal drain was drilled in an undeveloped Reservoir A for the first time in an offshore carbonate sequence, using advanced LWD acoustic and high-resolution microresistivity sensors.
The well plan required maximizing the exposure of the most porous body in a thinner sublayer. This sublayer lies directly over a large, developed carbonate reservoir as part of the Upper Jurassic Carbonate sequence located offshore Abu Dhabi.
The flow test results during the drillstem test (DST) operation for the first appraisal well in the target reservoir produced at a rate that was greater than expected. Production log data were acquired and integrated with the LWD microresistivity image interpretation. In addition, in this environment, the inferred Rt and Rxo measurements from the LWD azimuthal focused resistivity tool were shown to be more reliable than conventional electromagnetic wave resistivity measurements, which are prone to exhibiting significant polarization, anisotropy, and bed boundary effects.
Lessons learned from the first appraisal well in Reservoir A for reservoir characterization and flow unit identification were used and implemented in the planning and successful delivery of the future horizontal wells.
Unlike the other reservoir subunits that are deposited within the same sequence, the field development strategy for these undeveloped reservoirs has been under review based on the recent data. The field development strategy used enhancements in well placement, formation evaluation, and production technologies, including extended reach horizontal wells, with maximized reservoir exposure in the sweetest zones, to compensate for the poor petrophysical character and low oil mobility.
This case study presents insights into the advanced geosteering and multidisciplinary reservoir characterization processes along these successful horizontal drains drilled in undeveloped Reservoir A
and the future horizontal wells. It also demonstrates the integration between the geological and petrophysical interpretation and the use of acoustic measurements and high-resolution microresistivity imaging. This combination has enhanced the understanding of Reservoir A in terms of the unexpected production performance and helped optimize efforts for the future field development plan.
Novel Method for Consistent Initialization of Reservoir Simulation Models with Oil/Water Paleo-Contacts
Authors: Patacchini Leonardo , Mohmed Farzeen , Lavenu Arthur P. , Ouzzane Djamel , Hinkley Richard , Crockett Steven , Bedewi Mahmoud 
Published: November 2017

Abstract
The classic method for initializing reservoir simulation models in the presence of a transition zone, based on primary drainage capillary-gravity equilibrium, is extended to account for partial reimbibition post oil migration. This tackles situations where structural events, such as trap tilting or caprock leakage, caused the current free-water level (FWL) to rise above deeper paleo-contacts.
A preliminary primary drainage initialization is performed with zero capillary pressure at the paleo (or deepest historical) FWL, to obtain a minimum historical water saturation distribution. From a capillary pressure hysteresis model, it is then possible to determine the appropriate imbibition scanning curve for each gridblock, which are used to perform a second initialization with zero capillary pressure at the current FWL.
With the proposed method, log-derived saturation profiles can be honored using a physically meaningful capillary pressure model. Furthermore, when relative permeability hysteresis is active, it is possible as a byproduct of the initialization to assign the correct scanning curves at time zero to each gridblock, which ensures that initial phase mobilities (hence reservoir productivity) and residual oil saturation (hence recoverable oil to waterflood) are modeled correctly. This is demonstrated with a synthetic vertical 1D model.
The method was implemented in a commercial reservoir simulator to support modeling work for a giant undeveloped carbonate reservoir, where available data suggest that more than 3/4 of the initial oil in place could be located between the current FWL and a dome-shaped paleo-FWL. This work is used as a case study to illustrate the elegance of the proposed method in the presence of multiple (or tilted) paleo-FWLs, as only one set of capillary pressure curves per dynamic rock-type is required to honor the complex log-derived saturation distribution.
Porosity Measurements on Drill Cuttings - Comprehensive Inputs to Formation Evaluation near Real-Time While Drilling
Authors: Kesserwan Hasan , Alshanqaiti Elham , Jin Guodong , Nuic Ivo 
Published: November 2017

Abstract
The use of drill cuttings in the reservoir characterization can help to understand the reservoir properties. This is promoted by the need of near-real time formation parameters to calibrate the logs acquired while drilling and/or in horizontal wells where conventional coring is not an option. Similar to the cores, the measurements performed on cuttings are always challenged against both experiments and interpretation procedures, however with larger margins of uncertainties. We focus this study on measuring the cutting porosity and pore size distributions to highlight the impacts of cutting size on the reliability of the results to represent the actual formation porosityespecially for complex rocks.
We determined the porosity using the solid and the pore volumes of drill cuttings obtained from sandstone and carbonate rocks. After cleaning and drying, the solid volume is measured using a gas pycnometer. The pore volume is then measured using NMR T2 relaxation in saturated surface dry drill cuttings (SSD). The porosity and pore size distributionsmeasured on sandstones and carbonates cuttings (down to 1 mm) matched very well the core measured values. The complexity of the rock, though, is found deterministic for reliability of the cuttings especially for the carbonates at reduced cutting sizes. We also emphasized on the effects of the water-film that forms on the surface of the cuttings on porosity readings.
QRA Ruleset for the Sour Pipelines of the Kashagan Field
Authors: Scaperdas Athena , Lines Ian , Young Marc , Pennicott Philip 
Published: November 2017

Abstract
Many but not all Oil & Gas operators develop company rulesets for Quantitative Risk Assessments (QRAs). For those that do, it is to ensure a consistent and high standard approach across all company assets, aiming to achieve a balance between modelling simplification and complexity. A QRA ruleset has been developed for the Kashagan field in Kazakhstan by the North Caspian Operating Company NV (NCOC), with the purpose of addressing the specific challenges associated with quantifying the risk of toxic releases from high-pressure, high-H2S content pipelines. This paper summarises the analytical approach given in the ruleset, and explains how it was developed, by bringing together the most up-to-date guidance available in the industry.
The main themes presented in this paper are: methodologies used to assess H2S risks to the general public, including the effect of concentration fluctuations and the choice of averaging time; the choice of dispersion model for far-field dispersion; and defining appropriate 'source terms’ for the dispersion modelling in order to account for the effect of ground cover on buried pipelines and to allow the full-bore ‘crater’ releases to be characterised more realistically. Calculating the probability of releases, especially those for the largest full-bore releases, is another important consideration.
Digital Slickline: One Stop Shop for Well Intervention
Authors: Jongnarungsin Sarunya , Jafar Feras Abu , Ali Abdulla Bu , Laoroongroj Ajana , Hariry Ahmed El , Puttisounthorn Toon 
Published: November 2017

Abstract
The current low oil price environment has driven a renewed focus on managing costs while minimizing exposure to operational risk, and lightweight well intervention activities have not been exempt from this scrutiny.
Electric line (E-line) and conventional slickline are important and frequently used tools for light well intervention operations, and are often used at different times during the same well intervention program, leading to multiple rig-ups and rig-downs of the equipment, as well as the requirement to transport both units to the platform. This paper presents a case study of the use of digital slickline technology to perform typical slickline and typical electric line operations with the same digital slickline unit, thus saving costs and reducing risk by eliminating some rig up/rig down activities, minimizing equipment handling, and downscaling crew size.
Mubadala Petroleum performs rig less activities similar to other oil operators in the region. Both slickline and electric line equipment must be mobilized to the platform and rigged up separately. This creates inefficiency with logistics, operations, while increasing risk and results in higher overall operational costs. With the introduction of digital slickline to offshore operations, it has changed the way that Mubadala Petroleum performs rig less intervention.
The digital slickline data plots shown in this paper are representative real examples of its application. Interventions executed using real time digital slickline have proven to be safer, improve efficiency and are a more cost-effective way to conduct operations by having full real-time control of downhole tool and sensors. It also reduces total foot print of equipment and personnel during simultaneous slickline and electric line operation by utilizing a single digital slickline unit to cover both downhole mechanicals, perforation and real-time logging work scope without switching back and forth between units. Depth accuracy and shot detection was achieved with lower operational risk while working with perforation guns and explosives.
Material presented in the paper are from actual operations, with examples of perforation, depth correlation, pressure surveys, and pressure monitoring while perforating, and demonstrate the operational efficiencies and risk reduction being delivered.