bluuebunny/crossref_metadata_2025 huggingface dataset:
An Experimental Study on Interactions between Imbibed Fracturing Fluid and Organic-Rich Tight Carbonate Source Rocks
Authors: Liang Feng , Lai Bitao , Zhang Jilin , Liu Hui-Hai , Li Weichang
Published: November 2017

Carbonate reservoirs dominate 70% of oil and 90% of gas reserves in Middle East region, and imbibition is the main mechanism for fracturing fluid up-take during hydraulic fracturing stimulation process. Due to highly heterogeneous nature of tight carbonate source rocks, it is crucial to understand effects of the imbibed fluid on the mechanical, morphological and flow properties of the carbonate rocks. While the influence of imbibed fluids on the wettability of carbonate reservoir has been studied intensively, the research on effects of imbibed fluids on the texture and mineralogy of the carbonate rocks is very limited. This paper aims to provide a conceptual approach and workflow to characterize and quantify microstructure and mineralogy changes resulting from the imbibed fluids.

A thin-section of low permeability organic-rich carbonate rock sample with a dimension of 7mm × 7mm × 0.3mm (length × width × thickness) was used in the study. The sample was submerged into 2% KCl (pH = 7.1) fluid from one end to simulate the spontaneous imbibition process. Scanning Electron Microscope (SEM) was used to capture the sample’s morphological change before and after spontaneous imbibition. Energy Dispersive Spectroscopy (EDS) mapping was used to study mineralogy changes (dissolution and precipitation) before and after fluid treatment. Inductively coupled plasma (ICP) equipped with optical emission spectrometer (OES) detector has been used to quantify dissolved ion concentrations in the treatment fluid. Permeability and porosity were measured using core plugs (1" in diameter × 1.5" in length) before and after imbibition process with half-length of the sample submerged into the treatment fluid.

The SEM images for the thin-section sample show three zones with distinct fluid up-take characters. In Zone I, which was submerged into the testing fluid, considerable mineral dissolution has been observed. In Zone III, which was above the testing fluid level, considerable mineral precipitation was detected. While in the transition zone (Zone II, which was between the above two zones around the water-air level), minor amount of mineral dissolution was observed. The mineralogy changes resulting from the dissolution and precipitation have been identified by EDS analysis in all three zones. Gypsum and calcite were found to be dissolved in the imbibed fluids, while gypsum was found to be deposited on the rock surface in zones above fluid level. The observed gypsum deposition might result from the dissolution of the gypsum and calcite and re-precipitaion later from the imbibition experiment due to water evaporation and/or from sample drying process. Absolute permeability and porosity measurements for core plug samples show that both increased after the imbibition process.
Nano-Enabled Smart Materials and Sensors for Oil and Gas Applications
Authors: Ventura Darryl , Dolog Rostyslav , Darugar Qusai , Khabashesku Valery , Hughes Baker
Published: November 2017

This paper describes the use of nanotechnology for transforming conventional composites that are commonly used in oilfield applications into smart materials with the ability to transmit pertinent data from downhole operations and activities. The oil and gas industry already uses stimuli-responsive materials for numerous technologies including swellable elastomers in reactive packers and in heat/ fluid-activated expandable screens. This research details the digitization of stimuli-responsive materials through the integration of a network of conductive nanomaterials into an elastomer matrix. As a result, sensors with a wide array of detection capabilities become possible. For instance, it is possible to monitor the degree and rate of a material’s expansion downhole – such as in packers or sand screens. Such information can be used to detect tool deployment status, degradation, or even chemical detection. In addition, the conductivity data resulting from nano-enabled smart composites described here can be used to detect the presence of oil, water, or specific chemicals.
Seismic Characterization of the Shuaiba Formation in the Western Region of UAE, a Predictive Tool to unravel Shuaiba Facies Mosaic?
Authors: Zampetti Valentina , Perrotta Sonia , Chaari Ghassen , Krayenbuehl Thomas , Braun Matthias , Neves Fernando , Hu Jialiang
Published: November 2017

The Aptian Shuaiba Formation is among the most important reservoir units in the Middle East. Despite being extensively studied in recent years (Droste, 2016; Murris, 1980; Droste and van Steenwinkel, 2004; Yose et al., 2006;2010; van Buchem et al., 2002, 2010; Vahrenkamp, 1996), the interpretation of the Shuaiba depositional geometries, and specifically those associated with Shuaiba reservoirs, remains challenging in the seismic realm due to their intrinsic heterogeneity, variability and limited thickness.

An integrated and iterative analysis including regional geology, well and seismic data was conducted to unravel the internal depositional geometries and associated reservoir properties for the Shuaiba Formation in the western region of UAE. In the study area, spatial distribution and geometry of the Shuaiba seismic facies was mapped in detail using full-stack reflectivity, discontinuity, curvature and spectral decomposition seismic attributes and further integrated with available well data and analogues. The Shuaiba Formation is expressed on seismic by mounded facies characterized by an irregular appearance, with discontinuous outline of sub-transparent reflectors, crossing reflectors and a larger thickness than the surrounding facies. Reflectors may locally coalesce and form mounded features up to 70 ms thick. The areas between mounds are characterised by sub-parallel to inclined reflections. The latter could be interpreted as clinoforms, prograding from the isolated nucleation areas to their deeper surroundings. The base of the mounds is located just above the top Thamama B/base Shuaiba reflector and the top coincides with the top Shuaiba. Well data suggest that these mounds consist usually of Bacinella/Lithocodium facies and rudists. The detailed 3D seismic interpretation of the Shuaiba reservoir geometries indicates a complex depositional architecture, which results in a variety of potential stratigraphic trap geometries and a heterogeneous reservoir property distribution. The proposed integrated workflow can therefore be used as a predictive tool to unravel further prospectivity in the Shuaiba Formation and in similar complex carbonate reservoirs, as well as to significantly improve reservoir property distribution prediction in static models.
Benefits of Implementing Integrated Reservoir Management IRM Framework by Closing Gaps in People, Process and Technology - Second Act
Authors: Marzouqi Mohamed Al , Bahamaish Jamal , Saputelli Luigi
Published: November 2017

Integrated Reservoir Management (IRM) work processes enable upstream assets in sustaining production targets through the proper identification of performance improvement opportunities. IRM framework have been established since 2015 to assure quality and consistency in reservoir management best practices.

This paper shows the success cases where such complex management framework was deployed across 19 assets in a short period of time and minimum resources, reaching over 400 users including technical and business level personnel.

It was demonstrated through key examples how IRM helped the assets in (a) shortening learning curves, and hence reducing the total cycle time, resulting in increased productivity, (b) measuring KPI’s that cultivate proper behaviors to integrate the right multi-disciplinary efforts in delivering consistent results and (c) fostering a new culture that continuously challenge status quo with consistency.
1.800 Million $ Cost Optimization in ADNOC LNG Plant Maintenance by Applying Creative Ideas Kaizen
Authors: Ali Ahmed Al
Published: November 2017

Objective:

As UAE government has announced 2015 as innovation year and in line with ADGAS / ADNOC innovation strategy (kaizen) we have implemented creative ideas.

During day to day maintenance activities we came across many break downs and repeated problems.

These repeated problems consume a lot of man hours and materials.

To rectify these problems we have implemented many innovative solutions that resulted in plant reliability and cost optimization by using internal resources.

Method: This study explains the disadvantages of old system and how we resolved using innovative ideas of the following projects:Un availability of Instrument & plant air during compressor shutdown in utility plant, Consume more energy while using portable air compressor.Consuming energy for the VRU compressor panel which was not in use.Pilot flare Auto Ignition system fail to operate due to corroded tubing's and junction box.Un availability of pump well pressure valves feedback indication due to repeated mechanical lever failure.Maintenance team exposure to sulphur toxic gases.Delay the LNG / LPG & paraffinic naphtha ships loading during SOV failure.More energy consumption to remove the Sulphur blockage from the loading line.Consuming more manpower and materials.Non availability of deluge valve during fire emergency.Fuel gas loss for Utility plants due to Boil off Gas compressor trip.Failure of Sulphur inlet valve.

Results: Cost optimization of more than $ 1,800,000; enhance plant reliability and knowledge gained from accomplishing these projects. This knowledge will be shared with the audience.

Novel: The paper will encourage other Oil & Gas companies to implement innovative ideas to achieve maintenance and operational excellence.

Contents: General idea about Instrumentation in Oil & Gas General idea about our plant loaction and environement New back up air line Removal of redundant VRU panel Replace corroded SOV boxes at plant 19 Replace pump well pressure control valves limit switches Replace & Relocate Sulphur shore slope tank RTD junction boxes Sulphur loading line skin temperature Sulphur loading arm control panel LNG tank D-103 deluge valve cable fault Repeated trip of 49-K-0001 compressor Failure of Sulphur acid gas ESD valve. How much we have saved?
Enhanced Oil Spill Detection and Consequence Management Through Satellite Imagery
Authors: Ayasse Rob
Published: November 2017

Objectives/Scope

To outline how satellite technology can enhance oil spill detection and therefore consequence management, drawing on a comparative study of options by the Norwegian association of oil and gas operators; to use examples of successful detection in 2016 and 2017 in Saudi Arabia, the UAE and Qatar; to outline how collaborative satellite monitoring could be adopted by countries around the Arabian Gulf, possibly through ROPME/MEMAC or RECSO, patterned on Norway and the European Maritime Safety Agency's multistakeholder approach.

Methods, Procedures, Process

The presentation will begin with an explanation of the key benefits of using satellite technology for oil spill monitoring and enhanced consequence management, as well as the identification of likely polluters. It will use the case study method to demonstrate how it has been done successfully in 2016 and 2017 in Saudi Arabia, the UAE and Qatar; and finally, it will then provide a vision of how collaborative satellite oil spill monitoring and polluter identification could be used to great effect in the Arabian Gulf, by organizations such as ROPME and RECSO, modelled on examples from the Norwegian Clean Seas Association for Operating Companies (NOFO) and the European Maritime Safety Agency's (EMSA) multilateral monitoring program.

Results, Observations, Conclusions

The results of the paper will be twofold. First, the results of a recent 3year study by the association of Norwegian oil and gas operators, which looked at all the different technologies for detecting oil slicks (passive buoys, platform radar, maritime patrol aircraft, surface vessels and satellite imagery), examples will be summarized. That study concluded that satellite-based detection offers the best ratio of price to operational effect. Second, show examples of successes in identifying largescale oil spills in the Arabian Gulf with satellite imagery, such as the massive-scale blowout on an Iranian platform that happened on or about 8 March 2017, and which sent 9 separate oil slicks drifting towards the UAE. Other examples from Saudi Arabia, Qatar and the UAE will also be used, including how polluting vessels off the coast of Al Fujairah have been successfully identified. Against the background of these results, a conclusion will be drawn, which is that significant benefits would accrue from the countries in the Arabian Gulf adopting a collaborative oil spill monitoring program based on effective satellite technologies. This challenge is particularly pressing given that an oil spill at one end of the Gulf will inevitably threaten beaches and delicate marine ecosystems at the other end.

Novel/Additive Information

While standard in Europe since 2007, use of satellite-based monitoring in the Gulf is neither widespread nor wellknown. This presentation aims to address that knowledge gap.
A Field Case Study of an Interwell Gas Tracer Test for GAS-EOR Monitoring
Authors: Sanni Modiu , Abbad Mohammad , Kokal Sunil , Ali Razally , Zefzafy Ibrahim , Hartvig Sven , Huseby Olaf
Published: November 2017

Tracer technology has evolved significantly over the years and is now being increasingly used as one of the effective monitoring and surveillance (M&S) tools in the oil and gas industry. Tracer surveys, deployed as either interwell tests or single-well tests, are one of the enabling M&S technologies that can be used to investigate reservoir connectivity and flow performance, measure residual oil saturation, and determine reservoir properties that control displacement processes, particularly in improved oil recovery (IOR) or enhanced oil recovery (EOR) operations.

As part of a comprehensive monitoring and surveillance program for a GAS-EOR pilot project, an interwell gas tracer test (IWGTT) was designed and implemented to provide a better understanding of gas flow-paths and gas-phase connectivity between gas injector and producer pairs, gas-phase breakthrough times ("time of flight"), and provide pertinent data for optimizing water-alternating-gas (WAG) field operations. Additional objectives include the detection and tracking of any inadvertent out-of-zone injection, and acquisition of relevant data for gas reactive transport modelling. Four unique tracers were injected into four individual injectors, respectively, and their elution were monitored in four "paired" updip producers.

In addition to the reservoir connectivity and breakthrough times between the injector and producer pairs, the results showed different trends for different areas of the reservoir. The gas-phase breakthrough times are slightly different from the water tracer breakthrough times from a previous inter-well chemical tracer test (IWCTT). Residence times for the tracers indicate different trends for three of the injector-producer pairs compared to the last pair. These trends reflect and support conclusions regarding reservoir heterogeneities also seen from the previous IWCTT, which were not anticipated at the beginning of the GAS-EOR pilot.

This paper reviews the design and implementation of the tracer test, field operational issues, analyses, and interpretation of the tracer results. The tracer data has been very useful in understanding well interconnectivity and dynamic fluid flow in this part of the reservoir. This has led to better reservoir description, improved dynamic simulation model, and optimized WAG sequence.
An Automated Approach to Well Design: Using a Reservoir Simulator and Nodal Analysis
Authors: Noor Zainub , Khoriakov Vitaly , Boisvert Ian
Published: November 2017

Reservoir simulation is becoming increasingly complex because of more advanced wells in the fields, including intelligent and multilateral wells. Advanced completions are also evolving to increase recovery efficiencies. This increasing complexity presents two difficulties, which include the design of advanced completions within reservoir simulators and increased simulation runtime. To describe a well in a reservoir model, a reservoir engineer typically defines a network of hundreds of nodes using keywords and specifies properties for each node. This is a cumbersome and error-prone process. Additionally, detailed well models can slow down reservoir simulation and often cause poor convergence.

A new iterative round-trip approach has been implemented, in which an engineer imports an initial reservoir model into a nodal analysis simulator that models flow from the reservoir through complex completions to the wellhead. The simulator accurately models well production in steady state and designs completion strings in detail. After the design is complete, the nodal analysis simulator converts the well model into reservoir simulator keywords that are imported into full-scale simulations for transient analysis.

Using this method, reservoir simulators can also model multiple annuli, which was not feasible previously. Highly detailed well models of several thousand nodes that accurately describe completion strings can be generated automatically.

Reservoir engineers typically do not possess complex knowledge of well design because this is usually performed by completion/production engineers, who seldom have access to a reservoir simulator. Consequently, they have a limited ability to experiment with different well designs. This paper presents an approach that helps facilitate reservoir and production engineer collaboration, thus helping enable fine-tuning of final completion designs to maximize production, prevent early water/gas breakthrough, and increase overall recovery. This paper describes the application of the new process in an openhole well and presents various completion designs of the same well.
Oil Producer Tie-in Modular Skid
Authors: AlAwadhi Ammar
Published: November 2017

Abu Dhabi Company for Onshore Petroleum Operations (ADCO) manages all oil production reservoirs in all of its assets. Through ADCO's commitment to improvement, efficiency, and excellence, a new technology in the form of an Oil Producer Tie-in Modular Skid is being considered. The concept of the Tie-in Modular Skid is to integrate all wellhead tie-in and completion facilities into a single modular skid ready for field installment. Such wellhead facilities include: well head control panel (WHCP), SCADA RTU (telecommunications), chemical injection, solar panels, interconnected piping, field protection and safety equipment (SSV/ HIPPS), F&G detection, and finally a manual choke valve. The purpose of implementing this technology is to maximize production time by minimizing the tie-in period of conventional off pad oil producer wells, as well as maintain the high HSE standards associated with the wellhead area.

Safety, as always, remains the top priority in all of ADCO's processes; both surface safety valves (SSVs), making up the HIPPS, will maintain their location for the Christmas Tree's protection, while the flowline isolation valve will remain 100 meters away from the wellhead for the pipeline's safety. Accordingly, the Oil Producer Tie-in Modular Skid will be kept 80 meters away from the wellhead to allow for rig access during work overs without the necessary disassembly of all the piping and instrumentations as is the case in the current configuration or the business as usual (BAU). Moreover, the strategy deployed by ADCO for the integration of this production facility's technology is to free issue the critical items (WHCP, mechanical valves, SSVs, chokes, etc.) to the tie-in contractor whereas the bulk material will be included in his or her scope. Furthermore, the tie-in contractor will be responsible for the fabrication, assembly, transportation, tie-in, pre-commissioning, and commissioning of the skid.

Upon the implementation of the Oil Producer Tie in Modular Skid many advantages and benefits can be enjoyed. The skid's robust design is advantageous for enhanced operability and maintainability. Additionally, the implementation of this technology will decrease the wellhead facility's footprint, construction activities and commissioning time, tie-in schedule, storing inventory, procurement services and price agreements, HSE risks during construction, field service preparation for workovers, and finally logistics/mobilization. Lastly, the skid offers the convenience of relocation upon the depletion of the well.
High-Frequency Torsional Oscillation Laboratory Testing of an Entire Bottom Hole Assembly
Authors: Dennis Heinisch , Mathäus Winkler , Christian Herbig , Andreas Hohl , Hanno Reckmann
Published: November 2017

During the downhole drilling process, severe vibration loads can occur that affect the reliability and durability of tools in bottom hole assemblies (BHA) and may cause premature damage to the tools or their subcomponents. This paper presents a laboratory test setup for high-frequency torsional oscillations (HFTO) of a 23-meter BHA. Laboratory testing is highly important for investigating this phenomenon and developing appropriate mitigation strategies.

The paper provides a summary of the theoretical background for predicting the critical torsional eigenfrequencies, mode shapes, and the susceptibility of the BHA design to HFTO. In addition, the hardware and signal processing requirements for measuring HFTO and enabling differentiation of lateral and torsional vibrations are discussed. A laboratory test setup that emulates the critical mode shapes of the BHA is essential to thoroughly investigate HFTO, and to enable the development and testing of mitigation strategies.

The paper presents an appropriate test setup that has been optimized in advance by finite-element simulations. Additionally, the influence of boundary conditions (i.e., clamping the BHA) is discussed. A 240-kilowatt electromagnetic shaker system is used as an excitation source, and lateral and torsional vibration are measured by multiple triaxial accelerometers along the BHA. From the measurements, torsional vibration amplitudes and operational deflection shapes are derived and compared to results from simulation models.

The results from the presented laboratory HFTO test show an excellent correlation of the predicted critical frequencies and mode shapes from the simulation model to the corresponding operational deflection shapes of the tested BHA. The sensitivity of the BHA’s torsional dynamics to the boundary conditions is demonstrated by experimental variation of the string side boundary condition. Moreover, the test setup emulated the dynamic BHA’s characteristics and field-like vibration amplitudes were achieved during the test. Additionally, a method is proposed and applied to optimize correlation by variation of the excitation frequency. Using this method, a correlation of the critical HFTO mode shapes to the operational deflection shapes reproduced by the laboratory test of more than 96% can be obtained. The method demonstrates that the dynamic load profile to which the BHA is subjected during drilling operation due to HFTO can precisely be reproduced by the developed and presented laboratory setup. The ability to test entire BHAs with field-like vibration loads enables the development of fit-for-purpose drilling tools that can withstand extreme drilling conditions.
Optimizing the Secret Recipe to Drill Oman's Carbonate Reservoirs with Impregnated Drill Bit Technology
Authors: Lee Roger , Alshaqsi Khalfan , Richert Volker , Al-Ramadhani Asila , AlGharibi Bader , Al Sinawi Younis , Mohanty Ajay , AlMaktoumi Fahad , AlSabari Hilal
Published: November 2017

Amid suppressed oil prices, the Oman Ministry of Oil and Gas continues to invest in this country’s energy industry. Fortunately, upstream companies in Oman have the capabilities to help the ministry increase the country's output. Continued exploration and appraisal success allowed a private operator to rapidly increase production in the Shahad oil field. A key to this success in early production was reduction in drilling time – faster well delivery.

The operator's slimhole 6⅛-in. and 5⅞-in. sections are challenging directional build and lateral application drilling through dolomite and limestone. Polycrystalline diamond compact (PDC) bits were tested, but they did not show durability in distances drilled. The PDC bits used in this application experienced wear damage on the cutting structure that reduced bit efficiency to drill the longer distances and finish the section. Instead, the operator chose to deploy impregnated drill bits on turbine to drill longer distances and reduce tripping time. The next step was to drill faster. The operator partnered with a service company to develop and trial a new impregnated drill bit technology for improved drilling rates of penetration (ROP).

The service company uses an innovative process within a certified drilling optimization group that enables a structured approach for understanding the complete drilling environment. This successful process, founded on the continuous improvement cycle—plan, execute, analyze, and capture—delivers practices and technology recommendations to realize performance gains and significant well-time reduction. Areas of focus include proper hydraulics for cooling the cutting structure, accurate match of impregnated diamond materials to achieve improved penetration rates, and the correct gauge configuration to avoid bit sticking within the borehole. Using this process, two new impregnated drill bit designs were specially developed to drill the dolomite and limestone formation. The new technology was established to drill a lateral section with a turbine as the driving system in a carbonate formation with unconfined compressive strengths of 35k to 45k pounds per square inch.

The first trial of the 5⅞-in. impregnated drill bit matched the best field performance metrics of distance drilled and ROP. The second iteration continued to improve performance, delivering a 23% increase in ROP. The authors will present case studies to demonstrate how the latest technology impregnated drill bits contributed to faster well delivery for this operator's drilling program in Oman.
Advancing the Understanding of Openhole MultiStage Completion Systems in Khazzan—Hydraulic Fracturing Execution and Analysis
Authors: Ishteiwy O. A. , Casero A. , Al-Shueili A. , Turk G. , Roy A. , Al Manji A. , Dawson W. , White D. , Kurniadi S. D.
Published: November 2017

The Khazzan development in the Sultanate of Oman operated by BP includes a multi-layered gas reservoir with stresses impacted by tectonic activity which has led to numerous challenges around multi-stage hydraulic fracturing of horizontal wells within the field. These wells were primarily focused on cased-cemented horizontal sections through the reservoir but a decision was taken in 2014 to trial openhole multistage (OHMS) completion systems to understand their applicability in this field and the potential advantages such systems could bring with respect to the challenges seen in the cased-cemented systems. Two such systems have been run to date in the Khazzan development. Significant consideration has been given during the planning phase to follow a systematic process of implementation to deliver an effective learning curve with clear understanding of the impact of design and execution changes between wells.

This paper will describe the details, including completion and fracturing design, fracturing execution and surveillance, and post-fracturing clean up and production, of the second OHMS well in the Khazzan development. The second well has built on the success of the initial trial and the well has been designed to demonstrate the repeatability and the reliability of this completion type in Khazzan. It was also tailored to further the understanding of some key unknown or uncertain elements of the fracturing treatments following the analysis and interpretation of the first OHMS completion.

Specific focus areas that will be addressed in this paper include the use of a hydraulically activated toe fracturing sleeve, the effect of a reduction of mechanical packer spacing on fracture staging performance and efficiency, ball drop efficiency, and overall fracture execution efficiency improvements.

A comparison of the system's performance across different reservoir quality will be examined, with the second system having been deliberately deployed in relatively low reservoir quality rock. The impact of various degrees of over-flush and under-flush on the individual fracture stage production performance will be reviewed. This is an important consideration for more conventional Middle East reservoirs and is often perceived to be a barrier to the implementation of the highly efficient systems currently deployed by North America.
Engineering Documents from Jurassic Era to Avant-Garde
Authors: Tayfor Hussam , Kumar Anish
Published: November 2017

Documents quality and documents control was of less significance in the past. This has been mainly due to limited drawings tools available in the industry for the data management and due to considerably small scale of technical requirements for data filing, restoration and archiving.

Majority of engineering data and drawings in the 70s’ were available as hardcopy versions of various sizes & types (ammonia print, tracing papers, hand written data sheet …etc.).

Filing and document control was solely maintained in hardcopy logbooks and registers. Introduction of computers based application helped to some extent in generating index for documents which in-turn enhanced filing administration and document controlling.

The uprising in the industrial technology took place in the 21st century has come with major challenges and compelled emergent of parallel technologies for the database management and control systems.

The above scenario was experienced also to Gasco Company throughout the years of its rapidly progressive development.

With the idea in mind; plant data shall always be maintained to reveal the 'As-Built' status, Gasco has emerged vastly on the deployment of the latest integrated technology that can deliver the ultimate intelligent database management platform for sustainable and traceable as-built database and integration at the corporate level.
History Matching of Integrated Reservoir Simulation Model for Green Field Offshore Abu Dhabi
Authors: Semenov A. , Altaf B. , Allouti A. , Bu-Hindi H. , Ibrahim L.
Published: November 2017

Integrated reservoir simulation model (IRSM) is a common working tool in multidisciplinary teams nowadays. Usually such models constructed and used before field production startup, on the pre-project stage. But authors are commonly missing part about how good is the prediction ability of the model after first production and pressure data acquired? History matching, calibration of all parts of integrated model (reservoir, well, surface pipelines) requires constant efforts of multidisciplinary team or even building new model from scratch. In the scope of the paper the preparation of dynamic integrated reservoir simulation model and calibration based on 2 years of Phase 1 field production is covered.

Commercially available reservoir simulator with fully coupled network infrastructure was used for modeling purposes. Multi-reservoir static model grid was linked with networks (oil production, gas and water injection). Real time data from well downhole gauges (including smart wells) and MPFMs were used for reservoir models HM. Additional data from surface gauges and export meter were used to calibrate pressure drop in wellbore and surface pipelines.

Initially created IRSM was not able without HM stage and calibration to accurately predict the reservoir performance and pressure in the surface production system. Exceeding complexity of the model was decreasing the accuracy of the forecast even more. Only after history matching step for all wells using daily pressure/rate data and implementation of real pipeline layouts, the model was used for different purposes such as well placement and business planning. Highly efficient prediction tool was constructed in the scope of the study.
Liquid Cement Premix System for Rigless P&A
Authors: Thom Douglas
Published: November 2017

Plug and Abandonment (P&A) operations are integral to the decommissioning phase of an offshore installation. The most critical aspect of the P&A is the cementing operations, in which cement slurry is used as barriers to isolate potential flow zones and verify abandonment. Typically, this is conducted at the rig site where bulk cement, water and specialized additives are mixed and pumped downhole. While the practice of cementing is well established, it can be challenging to conduct such operations efficiently in P&A environments such as dealing with ageing equipment or where a rigless solution has been adopted.

This paper will highlight the use of a Liquid Cement Premix (LCP) system on a rigless P&A project in the North Sea in which three wells required permanently abandonment. The LCP system was used as an alternative to conventional cementing operations due to its benefits in equipment reduction and more efficient logistical solution. Due to the importance of the LCP operations, significant measures were required in order to ensure the quality control of the LCP. This paper discusses these measures adopted in the onshore, offshore and laboratory phases of execution.

It was found that LCP can provide a superior alternative to conventional cementing operations as the product behaved in a reliable and consistent manner. All three wells successfully abandoned with no nonproductive time (NPT) attributed to the LCP operations.
The Value of Rate, Temperature and Pressure Surveillance in Steam Assisted Gravity Drainage SAGD Process
Authors: Shaker Wisam , Chen Zhangxing , Walker Greg
Published: November 2017

Steam Assisted Gravity Drainage (SAGD) is used in West Canadian Sedimentary Basin (WCSB) for heavy oil recovery and numerical simulation is quantitative tool, which can be used to evaluate the SAGD performance and test developments options. This paper starts with the assumption that a single model is unlikely to be correct, and cannot represent the range in the outcomes due to the reservoir complexity and fluid heterogeneity. An alternative is to generate a number of models through an assisted history matching (AHM) process, with the intent of providing realistic estimates of the remaining uncertainty and quantifiable options to reduce the uncertainty. For a new piece of surveillance to add value, our working hypothesis is that the new surveillance should not be correlated with existing surveillance to avoid redundancy, and that the reduction in the range of acceptable models provides a way of quantifying the value. For our SAGD study, we are evaluating if temperature and pressure surveillance in observation wells has value, and how they should be included in the objective function.

A synthetic two-dimensional SAGD model was used in the simulation, with a known truth case against which we can test the efficiency of different types of surveillance to recover the true reservoir performance. Three observation wells are distributed through the model with five stations for temperature and pressure measurements. To test the value of the temperature measurements and observer well, a blind searching algorithm was use initially to avoid introducing a search bias that could distort the correlation. Rate, pressure and, temperature misfits were calculated for each experiment. The model with less than 5% rate misfit were filtered and run for several years in prediction with the same depletion plan. The improvement in the lower confidence bound for the value of the field used as the benefit of the surveillance.

A second test was to use an exploitative search technique on a simple arithmetic objective function. As expected, the global minimum did not represent the truth case performance, though the truth case was in the intersection of the surveillance constraints of matching pressure, rate and temperature within noise. The correlation between temperature and pressure surveillance show some correlation, such that there is some redundancy, yet the analysis of the models resulting from both parts showed that pressure and temperature surveillance have reduced the uncertainty in the future outcomes by 84% in cumulative oil production and 82% in the NPV.

The proposed workflow used here will allow quantifying the potential of adding a new surveillance to the field and/or specifying the number and locations of the required observation wells which properly capture the steam chamber development and pressure propagation throughout SAGD reservoir.
Real-Time Resistivity Monitoring Tool for In-Situ Foam Front Tracking
Authors: Haroun Mohamed , Mohammed Abdul Moqtadir , Somra Bharat , Punjabi Soham , Temitope Ajayi , Yim Youngsun , Anastasiou Stavroula , Baker Jassim Abu , Haoge Liu , Kobaisi Mohammed Al , Karakas Metin , Aminzadeh Fred , Corova Francisco
Published: November 2017

Surfactant Foam assisted CO2 EOR, though getting traction for its environomic mobility control potential, faces numerous challenges for deployment in HPHTHS heterogeneous carbonate reservoirs. Amongst the major challenges, the first is the lack of a surfactant formulation compatible with our carbonate reservoirs and the second is the absence of a foam and CO2 front monitoring tool either at laboratory or field scale.

In this study, a novel monitoring technique has been developed to track quality of the foam while core-flooding. This is essential to capture the onset formation, development rate and break-through of the said foam across varying length of core-plugs. This has been previously conducted in lab-scale by virtue of pressure response with or without expensive imaging methods. This tool complements the conventional method of studying pressure response with resistance measurements across the core allowing tracking of the foam generation and propagation. Various preconditioning smart brines (SB) were alternatively injected with the non-ionic surfactant APG, co-injected with gas, to generate foam in-situ in carbonate reservoir samples. In addition, we briefly discuss a new idea involving resistivity and pressure measurements for the optimization of foam (and CO2 foam) injection into porous media

The foam generation, stability and breakthrough were studied as a function of salinity, ion composition and injected pore volumes of the various brines and surfactant. Core-plugs of 2 different rock types were flooded with 4 variations of smart brines at a constant flow rate. The tested formulations were ramped up from 2 to 8 pore volumes. The response of the ΔP/PV integrated with the Δρ/PV curves were analysed to detect foam generation and breakthrough. This allowed an immediate characterization of the foam performance providing capability of tracking the foam formation/dissipation across the length of the core-plugs, essential for compatible successful foam formulation.

This novel method allowed for instantaneous resistance observations in lab-scale along with the pressure response. The performance of the monitoring technique provided a new dimension in understanding foam flooding. This was integrated to provide comprehensive analysis of the formulated foam. Our innovative method provides the capability of quicker screening to successfully generate foam in-situ in high salinity, hardness and heterogenic environment.
Monitoring of Greenhouse Gas Emissions From Space in the Middle East
Authors: Gauthier Jean-Francois , Germain Stephane
Published: November 2017

In June 2016, GHGSat launched the world's first satellite capable of measuring greenhouse gas emissions from targeted industrial facilities around the world. We offer a single solution to measure emission rates of carbon dioxide and methane from selected targets with greater precision and lower cost than ground-based alternatives, across a wide range of industries. GHGSat is deriving the emission rates of these sources from 12 × 12 km maps of the atmospheric column densities of carbon dioxide and methane produced using its patented sensor at a spatial resolution better than 50 m. Satellite mass is less than 15 kg. Our solution provides industrial site operators and government regulators with the information they need to understand and manage their greenhouse gas emissions better and ultimately to reduce them more economically. We will describe the system, including the sensor and satellite specifications. We will also describe our products and services, show how they apply to the oil and gas industry in the Middle East and provide examples of various levels of imagery taken from the region with our satellite.
Successful Field Application of Bulk Water Removal Debottlenecks Declining Songkhla Marginal Offshore Fields, Extending Economic Life
Authors: De La Sota Manuel
Published: November 2017

High watercuts (WC) and bottlenecked processing facilities can become killers for offshore marginal and declining fields. Bulk water removal has proven to be a solid quickly implemented solution for these production scenarios. This paper presents the challenges and lessons learned by Compañía Española de Petróleos, S.A. (CEPSA) fully owned subsidiary, CEC International Ltd. (CEC), in their successful field application of this principle to extend the economic lives of two declining and watered out Songkhla offshore fields located in Block G5/43 of the Gulf of Thailand.

In 2015, a redevelopment drilling campaign was undertaken in two fields of Block G5/43 in order to increase the oil production and accelerate reserves recovery. At that time, a need to increase the fluid handling capacity was identified to accompany the new production wells. After an intensive market exploration, and a positive field trial, the design selected consisted on bulk water removal by means of high efficiency hydrocyclones upstream the bottlenecked three-phase separator. The application of this design, together with a full revamping of the existing production facilities, commissioned in 2016, made CEPSA-CEC a pioneer in the use of this principle in South East Asia (SEA) and allowed substantial oil production increases with minimum incremental operating cost, extending economic life of the fields.

The application of bulk water removal can become a robust opportunity for those fields that are now experiencing a sharp production decline, with high WCs, and bottlenecked production facilities. The CEPSA-CEC case can serve as a model for expanding this technology and enhancing production from aging fields. This article presents project details and lessons learned hoping that they can serve to other Oil and Gas (O&G) companies facing similar limitations.
Deterministic and Stochastic Seismic Inversion, a Comparison Study Applied to Capture Major Heterogeneities and its Associated Uncertainties during Early Characterization Stage in Upper Jurassic Reservoirs in the UAE
Authors: Aamir Muhammad , Figuera Luis Gerardo , Hosani Khaled Al , Singh Maniesh , Ahmad Mula Nur , Solaiman Tarek , Qallabi Salah Al , Araque Arcides , Dike Nnamdi , Krissat Widad , El-Mawla Walid , Aly Omar , Elsayed Raghad , Mukherjee Anubrati , Nyein Glenn , Havelia Khushboo , Nafie Tarek
Published: November 2017

The studied Fields cover about 1900 sq km covering fourteen wells in Abu Dhabi, UAE. It was discovered in 1962 and developed by Abu Dhabi Petroleum Company. The objective of the current study is to illustrate the comparison between prestack stochastic & prestack deterministic seismic inversion results to better understand vertical and lateral heterogeneities of upper Jurassic reservoirs and their impact on property distribution during static modelling and further into dynamic model construction.
Upgrade Rig Moving System for Existing Land Rigs
Authors: Elrefai Mahmoud M. , Abd Elnaby Osama
Published: November 2017

In the last 10 years and due to high demand for new designs of drilling rigs to meet recent requirements for drilling challenges, NDC came up with new innovative solutions to convert existing old conventional moving rigs to new fast move rigs and/or other specific moving features such as drilling cluster wells. Conventional rigs' designs focused about drilling operation performance with less considerations to the fast rig move However due to technology improvement as a response to the stringent safety protocols and industry’s increasing focus on operational safety and efficiency.

NDC upgraded two types of existing rigs as followed: Fully dismantled rig with conventional design in 1981 to fast moving rig with advanced drilling features.Normal move rigs design to Cluster walking rig with unusual drilling features to be the first type in middle east.

Challenges lies in our main goal to meet latest API design requirements (Drilling loads, wind loads, rig move conditions, ..etc) as rigs had been designed for different design criteria.

NDC engineers along with rig designers and rig builders apply years of experience to deliver optimal solutions based on material selection, service application and functioning criteria.
Pipeline Leakage Detection Using Fiber Optics Distributed Temperature Sensing DTS
Authors: Mishra A. , Al Gabani S. H. , Jumaa Al Hosany A.
Published: November 2017

With increasing public consciousness and concern for the environment, recent pipeline leak incidents across the globe have proved that the cost to a company can be far more than the downtime and clean up expenses. As more stringent statutory regulations are getting introduced, cost effective and reliable leak detection systems are in demand.

"In the past few years, innovative distributed temperature monitoring techniques using optical fibers have demonstrated to be an efficient way to detect and localize leakages along pipelines. These techniques use a concept similar to Optical Domain Reflectometry (OTDR) for the localization, whereas the temperature information is extracted from the analysis of the scattered light through Raman or Brillouin scattering processes. Raman-based systems were first proposed and used in practical applications, while the Brillouin-based technique has been introduced in the early nineties and offers longer distance ranges" [2].

The manuscript details the methodology adopted to monitor gas pipeline leakages using distributed fibre optics sensing techniques. DTS has been introduced to UAE pipelines by GASCO through their first ever installation in HRS (Habshan - Ruwais–Shuweihat) gas pipeline followed by HMT (HabshanMaqtaTawelah) Pipeline Projects.