bluuebunny/crossref_metadata_2025 huggingface dataset:
Assessment of Reservoir Quality and Maturity using Near-Real Time Surface Measurements: Diyab Source Rock In Abu Dhabi
Authors: Ali H. , Bondabou K. , Van Laer P. , Baig M. Z. , Raina I. , Dasgupta S. , Ammar M. , Dmello A. M. , Khan S.
Published: November 2017

Estimating reservoir potential and placing the well in appropriate zones for production can be complex and challenging in an unconventional play. Diyab source rock located in the United Arab Emirates close to Abu Dhabi is an example of such a complex unconventional. Rise in unconventional exploration is mainly driven by advanced and improved technology. One such advancement in technology is the use of advance surface measurements in unconventional plays at well site which being comprehensive reduces interpretation uncertainty; enabling fast near-real time decision making.

Some key inputs in estimating reservoir potential of a source rock play are fluid type, rock texture, lithology, Total Organic Carbon and maturity. Reservoir fluid quality assessment in near real time through compositional fingerprinting of lighter alkanes (C1 - C5), heavy components (C6 - C8), aromatic components (C6H6, C7H8 and MCC6) and non-hydrocarbon components (Helium and CO2). Advanced cuttings characterization at the well site provided minerology quantification using XRD and XRF, texture interpretation using high resolution digital imaging. TOC was measured using the combustion method. Maturity was estimated using a novel technique of diffused reflectance Infrared Fourier spectroscopy.

Fluid composition analysis results were used to characterize reservoir fluid type while the rock measurements were used to identify rock litho-facies units. Two main reservoir fluid types were identified in the Diyab source rock. Quantitative surface measurements were available prior to any downhole well logs or lab analysis results. Fluid type analysis was used to aid in the planning of the well logging and core analysis program. Fluid type results were later validated using core measurements. Surface measurements of mineralogy and TOC were compared to the log analysis and core analysis results. An excellent match between the two was observed. Over the interval where core was not available, surface measurements enabled calibration of log interpretation results which were affected due to complex mud additives. Maturity estimation using diffused reflectance infrared Fourier spectroscopy technique was compared to the Vitrinite reflectance (where available) and Bitumen reflectance measurements. A good match was observed between the two.For the first time in Abu Dhabi, a unique workflow of advance surface measurements were adopted to provide near-real-time reservoir fluid composition, quantitative total organic content and maturity assessment in unconventional plays; which enabled us to carry out reservoir quality assessment in the Diyab source rock.Maturity assessments while drilling on cuttings were first ever done in Abu Dhabi.Advance cutting measurements were used in designing core analysis strategy
New Approach to Chemical Diversion Using Biodegradable Particulates and Fibers in Matrix Acidizing: Kuwait Case Studies
Authors: Al-Othman Mohammed , A-Matrouk Yousef , Ahmed Zamzam , Ashkanani Meshari , Buhamad Ali , Al-Dousari Mohammad , Ahmed Abdul-Samad , Fidan Erkan , Mahmoud Wael , Liu Hai , Salem Abrar , Nikolaev Max
Published: November 2017

Heterogeneity across the producing interval is typical in oil and gas wells; it is rare to find uniform production distribution or fluid injection across a substantially long interval. Hence, diversion during matrix acidizing is critical, especially if the downhole pressure and/or temperature are high.

In two Kuwait Jurassic fields, two wells were completed in an over 100 ft producing interval across a carbonate reservoir. Reservoir temperature is 280°F, and the estimated reservoir pressure is 11,000 psi. Multiple matrix acidizing trials to enhance well productivity have been performed with conventional diversion techniques and, as indicated by the surface pressure response, were not effective. This requires an adequately engineered near wellbore diversion system that can overcome the challenge of these bottomhole conditions and form a uniform production distribution across a substantially long heterogeneous interval.

A new methodology was applied in two Jurassic wells that combined a multimodal blend of biodegradable particulates and fibers as a chemical diverter, and emulsified acids as main fluids for a matrix stimulation. In each diversion stage, the change in surface pressure ranged from 800 to 1,000 psi after the diversion pill hit the perforation tunnel. Moreover, a clear signature of diversion was demonstrated in the instantaneous shutin pressures. In another Kuwait field, the diversion pill was tested by using injectivity logging tests to monitor the changes in injectivity across the perforated interval during an acid fracturing treatment in comparison to the earlier injection profile. A remarkable change in injection was observed and a total of 80% change in the injection profile was quantified from before and after the diversion.

The diversion pill is relatively small in volume and is easy and safe to handle. Fibers help to maintain the carrying capacity and allow safe landing of the biodegradable material to the formation face. Only a few barrels are required to plug the opened or stimulated interval, and the method allows the following stimulation stage to treat the subsequent interval.

The first well revealed a 330% and 110% production increase in gas and oil rates, respectively. The production was set as one of the highest producers in the field. The second well yielded a 320% increase in total production, which set the highest record for the field. The new method is proved to be highly effective in terms of wellbore coverage, and highest production records in the field after matrix acidizing treatments.
Integration of Pressure Transient Tests in Fracture Characterization in North Kuwait Carbonate Reservoirs
Authors: Lamine S. , Richard P. , Steen E. Van , Pattnaik C. , Narhari R. , LeVarlet X. , Dashti Qasem
Published: November 2017

The North Kuwait Carbonate (NKJG) reservoirs are currently under development by KOC (Kuwait Oil Company). In addition to the matrix heterogeneity, natural fracturing poses extra challenges for the optimization of the field development planning. The presence of open, connected fractures presents opportunities for infill drilling but increases the risk of water invasion and drilling related issues. Numerous fracture modelling studies have been supporting both appraisal and development strategies of the fields.

The translation of the field observation and detailed fracture characterization using static BHI (bore hole image) and core data yields a series of geological concepts. These concepts capture end members of the spatial distribution of the major conductive features and provide a range of realizations for the geometrical extent of the fracture zones. Given the large uncertainty in the dynamic properties of the fracture; pressure transient analysis (PTA), complemented by core data, has proven to be key in narrowing the range of fracture equivalent permeabilities and porosities that are carried forward in the history matching step.

This paper focuses on illustrating the integration of different aspects of Pressure Transient Analysis data to pre-condition the discrete fracture network (DFN) model realizations.

Comparison between KH from well test and log data allows to discriminate fractured from matrix wells. Dedicated sector models around fractured wells are built to assess the impact of the matrix, faults and fracture properties on the transient pressure response. Numerical simulations are conducted directly on the static model with the fractures explicitly captured as discrete surface features. For each DFN configuration, a sensitivity analysis of the fracture properties is performed and the characteristics of the resulting pressure derivatives are then compared against the well test data to select the plausible realizations that honor both geological and flow data.

In this paper, a series of examples demonstrating the application of the methodology are presented for different areas of the field.
Contribution of Tidal Analysis to Reservoir Monitoring - Field Case Study in a Fractured Reservoir Offshore Abu Dhabi
Authors: Faidouzi Mohamed Mehdi
Published: November 2017

Offshore reservoirs are subjected to pressure loading from the ocean tide. The resulting pressure fluctuation, notably its amplitude and phase, provides valuable information about the formation compressibility and heterogeneity. The purpose of the present study is twofold: first to propose a method for calculating tidal efficiency from harmonic analysis of regional tide stations and detrended bottomhole pressure, and second to compare the compressibility from tidal analysis to that obtained from rock mechanics measurements and material balance. This case study is on a fractured oilfield for which matrix laboratory measurements alone cannot capture the large scale formation compressibility which is driven by the .fracture distribution.

This paper will show how, in the absence of seabed pressure measurement, a synthetic diurnal tide can be simulated by interpolating the harmonic constituents of neighbouring tide stations. A new procedure combining Savitzky-Golay filter and cubic splines gave satisfactory results to filter out the tidal signal residual from the reservoir transient response. The tidal efficiency and pore pressure compressibility, computed through history for several wells, showed a clear correlation with the fracture tendancy. Also fluid effects, caused by higher water saturation in downdip wells or gas breakthrough, produce a clear signature on the tidal efficiency.
Enhancing Sustainability in Acid Gas Flare Operations
Authors: Dutt Indrajit , Hassan Yasser
Published: November 2017

Facility designs consider common acid gas flare for multiple plants operating in the complex, based on cost optimization considerations. Such designs involve common Flare KOD, which is difficult to maintain, as multiple plant shutdowns are not feasible during shutdown planning. Common stand-by Flare KOD with suitable isolation provisions from different plants’acid gas headers ensures timely maintenance and thus enhances the sustainability of the Acid Gas Flare Operations.

Due to presence of high levels of acid gases with moisture, acid gas flare streams tend to be highly corrosive. This poses safety threat to operating personnel, by loss of containment of toxic gas from vessel rupture or possible toxic gas leaks through KOD flanges. This situation was encountered in one of the GASCO operating complexes, where 2 existing plants shared a common flare KOD and a third existing plant via a different KOD was connected to the same acid gas flare.

Original design envisaged maintenance of the acid gas flare by inter-connection with one of the existing hydrocarbon flares but safe inspection of the acid gas flare KODs could not be conducted. Non-intrusive ultrasonic scanning indicated severe corrosion in one of the existing KODs at various positions. However, due to absence of proper isolation facilities, internal inspection / replacement of the existing KODs was not possible without a total shut-down, which was not permissible.

To overcome the problem, a standby flare system was studied to improve operational and maintenance flexibility, but was not implemented due to costs that were considered excessive. Instead, a more cost-effective solution based on installation of a standby KOD was implemented to address the critical Process safety issue. For installation of the new facility without any plant shutdown, several hot taps were required on the flare header.

Implementation of the Standby KOD costed less than USD 8 Million, substantially less than the estimated cost of around USD 100 Million for Standby Flare project, while providing the desired level of operational and maintenance flexibility.

Also, subsequent to the installation of the Standby KOD, an existing flare KOD, experiencing severe wall thinning due to corrosion, could be replaced without any plant shutdown. Reliability of existing acid gas flare KODs to resist toxic gas leaks has now improved with routine internal inspections.
Major Energy Saving and Revenue Generation Initiatives in GASCO Bu Hasa NGL Plant in 2016
Authors: Saleh Ahmed
Published: November 2017

This presentation will discuss Four Energy Efficiency initiatives were taken in 2016 in one of the biggest NGL Producing Plants in the UAE (GASCO-Bu Hasa).

They are: C3+ Recovery Enhancement: Increased the discharge pressure of HP compressor (2K-103/203) by 1 bar over the current operating pressure of 27.2barg. As an output, overall C3+ recovery increased by 0.3-0.4wt% depending on consistent operation at test run conditions.Utilizing 36" HP Line for Residue Gas: 36" BHGP line designed for diverting the excess HP gas, this was innovatively utilized for diverting excess Lean Gas and avoiding residue gas flaring.Savings through Advanced Process Control (APC): Advanced Process Control (APC) was implemented in Bu Hasa in 2009. During Jan & May-2015 tuning exercise initiated for all APC Controllers through GASCO in-house team.Savings through Internal & External Leak Survey: GASCO Bu Hasa NGL plant has taken the proactive approach to reduce hydrocarbon leaks by implementing an Internal and External Leak Detection and Repair Program.
A Novel Non-Acid Stimulation in Deep HPHT Naturally Fractured Gas Sandstone
Authors: Jianxin Peng , Mingguang Che , Guoqing Zou , Jiangyu Liu , Liao Wang , Rui Gao , Juan Xie , Leifeng Meng , Runqiang Fan
Published: November 2017

KeShen gasfield is a low matrix permeability intensely naturally fractured tight sandstone reservoir in Kuqa gasfield of Tarim basin, West China, with the characteristics of high-pressure 120MPa-140MPa, ultra-depth 6700m-8000m, high temperature 160°C-190°C, and long lateral 200m-300m. A non-acid stimulation was trialed in five wells and the post-production was surprised.

During drilling, a large number of barite is used to increase mud weight, and some calcium carbonate is used to avoid reservoir damage, But the damage is usually serious because of hundreds of tons of mud leakoff and the drilling fluid cakes. A non-acid cheating agent was trialed for removing the damage and increasing the production, based on the cheating mechanism, the divalent metal ions will be chelated by cheating agent, and barium or calcium ions will be preferentially chelated.

The non-acid cheating agent is an alkaline chelate with density 1.03g/cm3, the dissolving capacity of chelating barium ions is increasing by the chelating agent concentration and temperature. The concentration is usually from 25% to 30%, and the capacity of chelating barite ions is about 12.5-12.8g/L at the temperature of 170 °C. The reason for using chelating agent to remove the damage is that fresh acid and reacted acid can make strong corrosion to tubing string in the process of acidizing in high temperature reservoir. On the condition of 140 °C, the laboratory experiments indicate that the corrosion rate of fresh acid and the residual acid is 17.4g/ (m2·h) and 3g/ (m2·h) respectively, however, there is essentially no string corrosion observed when using the chealting agent for removing the damage. The non-acid cheating agent was trialed for five Wells. The general pumping rate is from 3.0 m3/min to 4.4m3/min, and the total volume of cheating agent is about 400m3. The gas post-production is about from 60×104 to 70×104m3/d, similar to that of adjacent wells to which acidizing or hydraulic fracturing are applied. The flowback fluid of the non-acid stimulation wells is tested, the results indicate that the maximum content of barium sulfate is 3200 mg/l, and the maximum content of calcium ion is 4382mg/l.

The non-acid stimulation is an effective method for high temperature intensely naturally fractured gas sandstone, no tubing corrosion.
First Attempt of the Multi-Well Simultaneous Steam Stimulation for Offshore Heavy Oilfield: A Case Study
Authors: Han Xiaodong , Liu Yigang , Wang Qiuxia , Zou Jian , Liu Hao , Wang Hongyu , Zhang Xiang , Wei Bing
Published: November 2017

Limited by platform space and equipment capability, thermal fluid injection was conducted for each individual well during heavy oil development with cyclic steam and flue gas stimulation in NB35-2 Oilfield. The single well injection mode results in severe gas channeling from injection well to adjacent production wells caused by areal pressure imbalance and high development cost. Measures must be taken to improve the recovery effect and economic benefits, especially in the low oil price environment.

The idea of multi-well simultaneous steam stimulation for offshore heavy oilfield was proposed and applied for actual practice in NB35-2 Oilfield. According to reservoir simulation results, formation pressure distribution could be much more even when thermal fluid was injected into the formation from different wells simultaneously. Besides, the overall developing cost could be greatly reduced by lowering the integral operating cost. For further controlling the gas channeling, the foam and temperature-sensitive gel were also used for gas channeling plugging. Based on the capacity of current steam and gas generator, two thermal wells were selected for field trail.

During the simultaneous steam and flue gas injection process of well X1 and X2, no gas channeling phenomenon occurred from the injection wells to adjacent wells which means that no negative impact on the production wells was induced by the injection operation. And the multi-well simultaneous steam stimulation combined with chemical plugging has displayed positive effects in controlling gas channeling. The daily oil production rate of these two wells were increased from 28.77 m3/d to 38.87m3/d, and 23.68 m3/d to 35.71 m3/d, respectively when compared with its value before steam injection. The predicted overall incremental oil production amount is about 5250 m3, and the period of validity is about 180 days. More importantly, compared with the operating cost of previous single well injection mode, the commuted operating cost of the multi-well simultaneous stimulation for one single well is greatly decreased by about 45 % and this kind of operating mode will surely bring more economic benefits.

This is the first time that multi-well simultaneous steam stimulation for offshore heavy oilfields is proposed and put into field trial. The favorable application result indicates that this technology could provide a useful guidance for the high-efficient heavy oil exploitation of offshore oilfield.
Gas to Wire With Carbon Capture & Storage: A Sustainable Way for On-Site Power Generation by Produced Gas
Authors: Andrei Maria , Sammarco Giuseppe
Published: November 2017

Natural gas has the potential to play an important role as a "bridge" fuel in the transition from fossil fuels towards a cleaner energy mix and a low-carbon future, due to its better environmental credentials (lower emissions of CO2 and other pollutants per MWh) and higher efficiency in power generation, compared to oil and coal. Natural gas is also suitable as a back-up fuel for complying with renewables and could turn in to a "final destination" fuel if Carbon Capture & Storage (CCS) technology would be competitive and conveniently located.

Natural gas with CCS could be a cheap and reliable low-carbon energy source in the long term and a critical technology for climate change mitigation, while delivering sustainable power.

Currently, the destination of most of the transported gas is as fuel for power generation, but the electricity can be generated anywhere, even at or near the reservoir source.

Gas-to-Wire (GtW) is the process of generating electricity from natural gas at or in proximity of the field, a different approach than producing electricity at a centralized power plant. In the Gas-to-Wire process a gas motor (usually a gas turbine) is placed close to the field and the gas is directly converted into electricity for own use or for sale to the local market (eventually transported by cables to the destination). For a more sustainable process, the CO2 produced by the power plant could be captured and injected underground (in a water layer or a depleted reservoir, if available in the area). Thus, the costs for CO2 transport and storage are reduced and NIMBY (Not In My Back Yard) reactions are limited, as everything remains confined inside the field and the only output is electricity.

Following this approach, the paper reports the results of a pre-feasibility study carried out applying the integrated GtW-CCS scheme to a gas production field. Economic sensitivities were performed determining the Levelized Cost Of Electricity (LCOE) and the CO2 captured cost as a function of: gas flow rate, power transmission distance and feedstock valorization.

Our analysis evidenced that the GtW-CCS scheme can be competitive in some circumstances, for instance: in remote assets (for own power), when associated gas is present and when wire transmission lines are located nearby the field. LCOE increases when capture plant is present and is particularly sensitive to location and feedstock cost.
3D SRME and Interbed Multiple Attenuation on Fully Regularized Common Offset Vector COV WAZ Data from Kuwait Single Sensor Survey
Authors: Jahdhami Moosa Al , Maag Jan Willem , Mueller Alexander , Narhari Srinivasa Rao , Kolawole Olusegun , Kidambi Vijaya Kumar , Al-Qadeeri Bashar , Dashti Qasem
Published: November 2017

Seismic data in Raudhatain field in Kuwait is strongly contaminated with multiples that impair the image of reservoir reflectors and challenge the structural as well as the quantitative interpretation. A reliable reservoir interpretation depends on an optimal attenuation of multiples (free surface and interbed). In this project, we demonstrated that a significant amount of multiple energy was attenuated by implementing 3D SRME together with data and model driven interbed de-multiple using two strong shallow reflectors as the dominant multiple generators.

The project was run with a primary objective of a successful multiple attenuation at the Jurassic level. Initially, 3D Fourier interpolation was applied to regularize and infill shots and receiver independently, to prepare the data for 3D multiple attenuation. However, the survey in some areas was undershot due to agricultural activities, resulting in massive data gaps which presented challenges for data regularization/interpolation.

Since the 3D data interpolation results demonstrated that this approach was suboptimal and inadequate to infill all data gaps, especially the large ones, a new strategy of incorporating legacy data (from the same area), was followed to infill these gaps in a more appropriate way.

The 3D merged dataset (vintage and new data) was used as input for 5D interpolation software which regularizes and infills the data in 5D senses producing fully regular Common Offset Vector (COV). The 5D interpolated COV panels show a significant improvement to the 3D interpolation results. With the incorporation of vintage data and implementation of 5D interpolation, the multiple predictions were improved.

After applying 3D SREM on the data, 3D interbed demultiple was implemented assuming that the dominant multiple periodicity at the target level is related to two shallow reflectors which have approximately 138ms TWT separation. As the real shallow data was too poor to use, full waveform inversion velocities were used to model the reflectivity of the shallow overburden, which used as input for 3D interbed multiples prediction together with the actual data. This 3D data and model driven approach successfully predicted the 1st order interbed multiples bouncing between these two reflectors.

This advanced 3D de-multiple approach has significantly attenuated multiples at target level allowing more reliable interpretation of the reservoir sections. Robust data interpolation and optimal implementation of novel multiple attenuation techniques were the key elements to the success of this project. Following the same processing approach on surveys or data with similar issues and challenges will help to address the seismic multiples and improve the reliability and accuracy of reservoir interpretation.
A Method for Quantifying Reservoir Connectivity Combining Reservoir Simulation and Production Data
Authors: Li Yanjing , Wei Xiaodong , Wu Ruikun , Tian Wenyuan , Chen Xin , Yan Xiaohuan , Zhong Weixiang , Yaliang Xia , Jin'e Chen
Published: November 2017

Static methods are commonly used to analyze the reservoir connectivity. However, the results are dubious. In this paper, an integrated method for validating results is proposed by using dynamic data and reservoir simulation. Static methods used to analyze the reservoir connectivity include seismic inversion, well to well correlations, pressure gradient, oil-water contacts, fluid property and so on. However, the study results by static data are dubious. In order to validate and improve the understanding of reservoir connectivity, dynamic data and reservoir simulation was used. First, the reservoir connectivity was investigated with the static methods mentioned above. Second, the static model was built on the basis of the geology integrated study result. Third, by combining both results stated above, a dynamic model was established. Finally, the understanding of reservoir connectivity was reasonably and effectively improved by conducting the production history matching and adjusting the static parameters. During this process, first, an unreasonable understanding on reservoir connectivity was recognized; then, a modified and improved static model was updated for the simulated results better matching production data, where the reservoirs connectivity was also updated.

Reservoir connectivity was successfully characterized with the proposed method in application field in Iraq. Results show that (1) reservoir connectivity characterization by static methods only is often not correct for local area in case field, which is validated by the simulated WTHP of some wells much lower than the actual measured data; and (2) an updated reservoir connectivity is more correct and reliable, which can improve the matching between reservoir simulation results and production data. Dynamic data and reservoir simulation is a effective method to study the reservoir connectivity incorporated with static methods. The integrated method should be trend for the reservoir connectivity characterization.
Pipeline Blockage Location by Pressure Wave Analysis
Authors: Stewart Neil , Jack Graham
Published: November 2017

The location of pipeline blockages continues to be a challenge to pipeline operators at exactly the moment when fast and accurate location of such blockages is fundamental to getting pipelines back in service. Methods currently exist for blockage locations; however, they are generally limited to the conditions in which they can be used or by their accuracy.

This paper discusses a new method for pipeline blockage detection using pressure wave analysis that analyzes the reflections generated by a pressure wave traversing the pipeline to the blockage location and back again. By connecting an ultra high-speed data logger to the pipeline, a pressure wave, generated by the rapid opening and closing of a bleed valve, can be recorded for analysis. The details of the pipeline and the fluid provided by the operator can be used to calculate the system acoustic velocity and, in combination with the recorded data, can, therefore, calculate the distance from the recording location to the blockage.

It can be shown that the theory behind the method is backed by results observed when using it to locate actual blockages within actual pipelines. Case studies are presented to show that the method can be used in both flowing and nonflowing pipelines, both on and offshore, in all fluids to identify where a blockage is located. The theoretical method for calculation of acoustic velocity for known system and fluid parameters can be shown to be accurate within tolerances when compared to the acoustic velocity gained in the field by recording the time of flight between two known points. It can be observed that blockages can be detected to a level of accuracy of up to 0.3% of pipeline length verified by comparison with pipeline features and with odometer data from a stuck intelligent pig.

The method presented in this paper differentiates itself from other pipeline blockage location systems by the use of pressure wave analysis. It has a higher level of accuracy than that claimed by other remote nonintrusive technologies available, therefore, giving pipeline operators the opportunity to target remediation work in a more efficient and cost-effective manner.
High Resolution Data Integration Aid on Achieving Successful Level-4 Multilateral Wells in Clastic Reservoirs of Minagish Field, West Kuwait
Authors: El Gezeery Taher , Al Shemali Nasser , Ebaid Adel , Kumar Jeevan , Padhy Girija , Das Om , Al Rashidi Tahani , Nugroho Cahyo , Pazos Jhonatan H , Noueihed Rabie S
Published: November 2017

The Middle Cretaceous Burgan reservoir in Minagish Field exhibits variable depositional clastic settings ranging from "Fluvial", "Fluvio-tidaT to "tidal wave sands". The sand bodies of Upper Burgan reservoir are highly heterogeneous in terms of the stratigraphic architecture implying extensive lateral facies variations, stacked sand bodies and varying petrophysical properties. Modeling the target sand channels and optimizing subsurface well trajectory with maximum reservoir contact requires "high resolution" geological and seismic data integration in order to minimize uncertainties related to correlations of timeline surfaces, channels geometries and sub-seismic fault network.

Since traditional logs could not capture the textural differences characterizing the reservoir zones, Real-time formation evaluation and geosteering challenges addressed to ensure the successful drilling and completion of level-4 "Multi-lateral" producers. A combination of the latest advanced geo-steering technology used in this well including Rotary Steerable, Distance to Boundary and Sourceless petrophysical evaluation while drilling.

The uncertainties in the geostatistical models were further reduced while drilling the first lateral section (LAT-0) by deploying extra deep azimuthal resistivity measurements. It has a higher precision and accuracy to consistently mapping the rise in OWC due to production operations with depth of detection up to 100 feet TVD above and below the well path and maintaining a standoff from the top of onset transgression undulating surface with poor sand facies.

The resultant mapping window provided accurate guides to update the geo-models. The formation evaluation along with borehole imaging and geo-correlation assisted in identifying a fault having a great impact on well positioning of the upper lateral due to a high amount of throw fault with significant formation dip changes. This is in turn eliminating risks of geosteering in such a complex heterogeneous reservoir.

The integrated approach utilizing geological, seismic, petrophysical and geosteering data provided better understanding for well positioning while drilling and achieving the MRC without exiting the sweet zones of targeted upper and lower Burgan sandstone in Minagish field and enhanced water free oil production.
Improved Reservoir Characterization in Complex Gas Carbonate Field in the North of the Sultanate of Oman
Authors: Al-Amri Mazin , Lukmanov Rinat , Al-Barwani Mohammed
Published: November 2017

Field N is a complex oil and gas field in the north of the Sultanate of Oman producing from several reservoirs. In this paper, the focus will be on Shuaiba gas reservoir, which is characterized by large variations in rock properties. An additional challenge is limited core data available and big gas effect observed from the logs. The described work was undertaken as part of an FDP update.

Gas correction effect and permeability modeling in such complex carbonate reservoir with the limited availability of representative core data is challenging. The density and neutron logs are affected by the presence of gas, which required advanced correction methods. The 1st applied technique of porosity correction comprised an iterative method of density and micro resistivity with simultaneous solution for residual gas saturation and corrected porosity. In addition, a new modification of gas correction was tried from Density-Neutron gas separation along with known PVT parameters was used for porosity calculation and gas corrections.

The log response of the Shuaiba reservoir in Field N looks like a classical illustration of gradual change of saturation from water leg to the transition zone and gas leg. However, flank well has been perforated close to the anticipated contact and produced gas for more than 200 days without water. As a result of comprehensive data analysis, a significant vertical heterogeneity of the reservoir was established. It was found that Gas saturation is a good indicator of permeability. A good relationship between fluid mobility from Wireline Formation Test data and water saturation from logs for gas leg was established. In the gas leg, all water is considered as irreducible, thus this is in fact relationship between mobility and irreducible water saturation. The relationship was then calibrated to permeability using the available core. As a result of this work, significant heterogeneity of the Shuaiba reservoir was captured in case of limited core data available. The remaining gas quantified for optimizing future development.

As part of this Study, an advanced gas correction method was applied resulting in more reliable Porosity evaluation. Besides, a new modification of the method for gas corrections from Density-Neutron separation was tested and showed good results.
Wellbore Trajectory Quality Management: A Key Approach to Safe Casing & Completion Strings Deployment in Complex Wells
Authors: Nobbs B. , Dao N. H. , Mollaret B.
Published: November 2017

Wellbore trajectory quality management is a key factor while deploying casing and completion strings. Depending on the type of directional drilling driving system, formation drilled, bit steerability and operational procedures, the trajectory can be smooth or very tortuous with significant additional local doglegs. In addition, when the wellbore surveying program is not sufficiently consistent (i.e. wellbore surveys with inadequate MWD survey sampling or Stationary Gyro surveying mode with a low sampling rate), the doglegs can be hidden and become potential difficulties down the track, resulting in ‘traps set open' for tubular running operations.

This paper presents a trajectory quality management methodology that enables the anticipation of stuck pipe problems or lock up situations when running casing and/or completion strings. This methodology involves different processes that permit the evaluation of: intermediate doglegs and wellbore tortuosityprecise casing positioning through the wellbore accounting for centralisation programtubular post buckling analysis

Robust 3D directional drilling models coupled with 3D stiff string T&D calculations (enhanced tubular string mechanics analysis) and adequate field data management are the key features of this successful approach.
Sweet Spot Mapping in the Montney Tight Gas Reservoir
Authors: Kato A. , Akihisa K. , Knapp L. , de Groot M. , Yamazaki K.
Published: November 2017

A common goal in unconventional plays is to create a sweet spot map by integrating all available data, including seismic data. This map could be utilized to optimize future drilling locations. Thus, in order to establish the workflow, we conducted a sweet spot mapping study in the Lower Triassic Montney tight gas play in the Western Canadian Sedimentary Basin, specifically focusing on prediction of lateral variations in condensate-gas ratio (CGR). A 3D geomodel was first created to obtain the 3D distribution of reservoir quality and completion quality properties which are expected to be potentially correlated with CGR. In the model, simultaneous AVO (Amplitude Variation with Offset) inversion results were fully utilized by geostatistically integrating with the well log data. Typical SRV (Stimulated Reservoir Volume) geometry in the study area was estimated from analysis using production data and microseismic data. For each producing well, average values for the reservoir quality and completion quality properties within the estimated SRV were obtained from the 3D geomodel to directly compare with the CGR value. Statistical analysis including crossplot and multiple-regression analysis was conducted to investigate the effectiveness of model properties as predictors of CGR. The analysis result implied that the reservoir depth and gas content are the most dominant properties for predicting lateral variations in CGR at seismic-scale. The reservoir depth is interpreted as a first-order control of thermal maturity and CGR. High gas content and low CGR is also observed in areas of higher porosity, which may correspond to secondary migration pathways for methane (Wood and Sanei, 2016); this is a second order control on gas content and CGR. Multiple-regression analysis was perfomed to obtaine a formula that explains CGR distribution by using the most effective combination of model properties. A CGR map was created by applying the established formula to the entire study area. The map of predicted CGR is consistent with the measured CGR. The map will be utilized for optimization of future drilling locations.
Assessment of Produced Water Reinjection in a Giant Carbonate Reservoir
Authors: Chen Peng , Willingham Thomas , Morrow Timothy Ian , Sowaidi Alunood K. , Stojkovic Dragan , Ning Jing , Gao Bo
Published: November 2017

Produced water reinjection (PWRI) is a proven field development technology which has been widely applied to numerous fields to optimize disposal of produced fluids while meeting reservoir injection requirements. However, PWRI has not been evaluated in many of the giant carbonate reservoirs which are relatively immature in the Middle East. In this paper, an on-going assessment of potential PWRI for a giant offshore field is presented.

The giant offshore oil field in the Middle East has been extensively developed since the 1970's. Seawater injection has been applied in the field since the 1980's and the produced water is disposed of through dedicated wells. The daily water production rate from this field has been increasing over time, and the continuous addition of oil producers and water injectors to capture the field reserves will further accelerate water production. Developing the most cost-effective solution to handle the significant volumes of produced water is crucial to ensure long-term operability of facilities and continued field production. A strategy to derive value from the produced water, which otherwise is considered unwanted, is to utilize PWRI. Proper laboratory assessment to determine specifications for PWRI will ensure the re-injected produced water is compatible with the reservoir fluids and that the target injection rate can be sustained through matrix flow.

The lab assessment to determine produced water quality specifications include an evaluation of the inorganic scaling potential of PWRI (fluid compatibility) and an analysis of the impact of oil carry over in the presence of fine particles on near wellbore injectivity. Thermodynamic modeling and bottle tests were performed to determine compatibility of PWRI with reservoir fluids (i.e. scale precipitation) and core flood tests at residual oil saturation with multiple rock types were completed to quantify the impact of oil carry over on PWRI specifications.

Thermodynamic modeling and bottle tests show PWRI has a lower inorganic scaling tendency than conventional sea water injection, and that scaling does not appear to be aggravated by PWRI. Core flood experiments indicate injectivity is maintained under anticipated oil carry over conditions (including upset conditions) across the various rock types evaluated suggesting PWRI may be an attractive technology to mitigate produced water disposal requirements while also meeting a portion of future field-level injectivity demand.
Using Aluminum Drill Pipe with Axial Oscillation Tools to Significantly Improve Drilling Performance
Authors: Mills K. , Menand S. , Grissom R.
Published: November 2017

Aluminum drill pipe has already been proven as a viable alternative to steel drill pipe when drilling long horizontal wells thanks to its lighter weight that does not compromise resistance to yield and buckling. At the same time, the development of unconventional wells has seen the deployment of numerous technologies to further improve the performance and increase the lateral section to reduce costs. An operator has recently and successfully tested a new aluminum drill pipe with an axial oscillation tool to push further the limits of the drilling system.

This paper presents the key findings of the case study using a mixed aluminum-steel string combined with an axial oscillation tool. First, the innovative drill pipe design is presented, followed by lessons learned during rig operations regarding pipe handling practices, rig compatibility and pipe inspection. Then, results of the drilling simulations performed during the well planning phase are presented. This modeling led to an optimum drill string design associating the steerable mud motor assembly, aluminum drill pipe, axial oscillation tool and steel drill pipe. The number and placement of aluminum drill pipe along the string was key to reducing friction and improving weight transfer between the bit and the axial oscillation tool.

Through extensive modeling and field data interpretation, this paper presents the comparison of the overall drilling performance between steel only and aluminum-steel drill pipe strings, and provides metrics in terms of weight transfer and rate of penetration improvement. This innovative and promising drill string design opens the doors to set new limits in terms of horizontal departure.
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

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

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

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.