bluuebunny/crossref_metadata_2025 huggingface dataset:
Study on a MEMS-Based Piezoelectric Energy Harvester
Authors: Tao FU , Xiaohan Pei , Qinghai Yang , Yili Hu , Eryang Ming , Siwei Meng , Shouzhi Huang
Published: November 2017

At present, most of the small-scale equipments used in monitoring underground oil exploration pipelines are powered by disposable or rechargeable batteries. These traditional chemical batteries have been unable to meet the needs of the system due to their large mass and volume, limited energy supply and possible environmental pollution. In addition, the huge depth of the oil wells can lead to a great deal of inconvenience during the replacement of the batteries. To solve these problems, a piezoelectric vibrator based on MEMS is proposed to achieve continuous supply of small downhole equipment in the process of oil/gas development.

In this study, after analyzing and optimizing the structural parameters of the device, a prototype is designed and fabricated through MEMS processing techniques including bulk silicon micro fabrication, bonding, and thinning. The prototype consists of a support layer, a piezoelectric film layer and a tip mass-block. Copper or silicon with appropriate stiffness and suitable for MEMS processing techniques are selected to make the support layer; PMN-PT with superior performance is selected to fabricate the piezoelectric film layer, whose working mode is d31. By running the energy acquisition test, the characteristics of the prototype's output voltage, power, and frequency are studied, as well as the possible requirements for the matching circuit.

The study shows that the test results are in good agreement with the calculated results of the theoretical model. The test results show that when the acceleration is 1.5g, the frequency bandwidth of the proposed prototype is 34.6Hz in air and 50.3Hz in silicon oil, and the output power can reach 35.4μW in air and 4.96μW in silicon oil.

Compared with the current mainstream piezoelectric thin film MEMS devices, this energy harvester based on MEMS technology has the advantages of superior output performance, simple fabrication, high anti-electromagnetic interference reliability, and easy integration with support circuit. This device will provide a new solution for the energy supply of downhole small-scale monitoring equipment.
Drains - A Hidden Source of Explosion!
Authors: Molelputhenpura Kuriakose Mathew , Adel Khalid , Al Awadhi Ibrahim
Published: November 2017

Proper functioning of the drainage system in oil and gas plant is vital for uninterrupted operation of the plant facilities. Among the various drainages, oily water drainage system is critical with high risk considering its hydro carbon content and accumulation of explosive vapours due to improper functioning of any components in the system. This paper presents some of the shortcomings in the design/arrangement/maintenance of the different elements and the improvements to avoid accidents.

The drainage types in GASCO plants are Clean Water Sewer, Sanitary Sewer, Oily Water Sewer (Accidentally Oil Contaminated / Continuously Oil Contaminated) and Chemical Drains. One of the unforeseen risks has caused an explosion in an existing oily water sump inside the process area. The sump was of concrete construction and the cover slab was blown up resulting in considerable damages to the surrounding pipes/support. There was no injuries to personal. The root cause analysis of the incident was done and a study carried out for a safety review of oily water drainage system at all plants.

A study was carried out to identify possible hazards/design deficiencies of the oily water drainage facilities and recommend measures for rectification and risk mitigation. The study identified that the lines are placed in slope & mainly "run dry" after use, liquid seal not available in some manholes causing HC vapour upstream movement, the manholes/sumps are closed, vent pipes size is small and some are blocked. These lead to accumulation/formation of hydrocarbon mixture inside closed sump, ignition by overheating of the pump installed over the pit and subsequent explosion. Recommendations for existing system include regular flushing of the lines with water to ensure transport of oily effluent & maintain liquid seal, regular removal of the floating hydrocarbon liquid from pits using vacuum truck, open up the manholes and use grating covers, provide self-skimming bucket where feasible, etc. Additionally, for new facilities it is recommended to lay the pipes horizontally to ensure liquid seal, provide turn-up elbows to reduce hydrocarbons accumulation in manholes, provide oil skimming/baffle wall in oil/water sumps, use classified equipment, carryout proper maintenance, etc.

The sump was reconstructed with the new design, which is now functioning well and the recommendations are being implemented in existing facilities and in all new projects.

The proposed improvements for the existing system as well as adopting the recommendations in future new drainage system can ensure the prevention of possible explosions and thereby reducing the related hazards to plant facilities/operations. Sharing of the related information among the international companies having similar facilities increases the awareness about such hidden sources of explosion in a drainage system and related pro-active mitigating measures.
The Value of Reservoir Surveillance - Applications to Fractured Carbonates Under Waterflooding
Authors: Shbair Alaa F. , Al Hammadi Hamdan , Martinez John , Adeoye Olanike , Abdou Medhat , Saputelli Luigi , Bahrini Fahmi
Published: November 2017

As reservoirs mature, subsurface flow complexity and surface production operation challenges increase. This brings the necessity of making capital-intensive decisions to sustain or increase reservoir potential in an optimum way. However, subsurface uncertainties affect decision success. Reservoir surveillance, a process that involves data acquisition, validation, analysis, integration opportunity generation and execution, can mitigate the outcome of such decisions in the presence of uncertainties.

Although Value of Information (VOI) is a well-known process for justifying data acquisition, engineers struggle to extract the relevant information from historical data to apply Bayesian approach.

The objective of this paper is to illustrate a methodology for identifying the value of information in reservoir management, in particular for deriving the conditional probabilities of success when new and imperfect data are acquired. A methodology to assess the value of reservoir surveillance is supported by two cases.

In the first case, the incremental value of Real-Time Reservoir Characterization (RTRC) in underbalanced drilling (UBD) was nearly 100 times the cost of the services; in the second case, the incremental value of permananet downhole gauges (PDHG) was near 230 times the cost of installation and services. Reliability of facquired data, among other uncertainties, resulted to be a key success factor for both cases; however, in worst-case conditions, the incremental value was always positive.
NGL Recovery - A New Concept for an Old Scrubber
Authors: Jariwala Ankur , Sanghani Pinkesh , Kvamsdal Dag
Published: November 2017

Gas scrubbers are designed to protect process equipment, such as compressors, dehydration towers, pipelines and molecular sieves from liquids. The efficiency of gas scrubbers for separating natural gas liquids (NGLs) is critical to the recovery of most of the entrained NGL before the gas is routed downstream to pipelines.

We present a specific case study in Southeast Asia where offshore production was delivering 300 MMscf/d of gas to an onshore gas processing facility. The gas was chilled in a mechanical refrigeration unit, and liquids were separated in a vertical scrubber equipped with a simple inlet device and mesh pad assembly. The scrubber was designed to handle 450 MMSCFD. Due to an inefficient scrubber design, the facility was experiencing NGL liquid carryover from the scrubber into the pipelines with the original design basis. The scrubber thereby showed significant amount of liquid carryover of 1,550 BPD of natural gas liquids into the gas pipelines.

Computational fluid dynamics modeling of the scenario clearly showed loss in separation efficiency and NGL carryover from the scrubber to the downstream pipeline, documenting that the existing scrubber was not suitable for such high gas loading and increased gas volume.

Customer approached Schlumberger to retrofit scrubber with a new design and resolve the existing liquid carryover issues which led to revenue loss. We have experience in desiging novel internals such as axial cyclonic inlet (ACI) in these kind of scrubber vessels. These have been tested and optimized in the laboratory using model fluids and further tested in a high-pressure real fluid testing loop. Test results show that ACI provides the required gas/liquid separation efficiency under the higher gas loading and thereby increases the overall separation efficiency to 99.9+%.

The retrofit scrubber was designed to process 450 -500 Mmscfd of gas and increase the NGL production by 8540 BPD showing high ROI for the customer. The scrubber with the ACI shows consistently higher separation efficiency even under turndown or lower inlet gas flow conditions.

We present details of the retrofit scrubber design, importance of using high efficiency separation internals, CFD anlaysis and present test results verifying the liquid carryover before and after implementation of the new inlet section.
Use of Surface Waves for Near-Surface Characterization and Drilling Hazard Reduction
Authors: Al Mesaabi S. , Mohammed M. , Tertrais B. , Bardainne T. , Garceran K.
Published: November 2017

To overcome the lack of information on the most superficial part of the near surface obtained by the use of the First Arrivals (refracted waves), we have implemented an innovative combined workflow that use the information from the Surface Waves (Rayleigh waves) to complement the first-break measurements. As the Rayleigh waves propagates along the free surface interface, they carry significantly more detailed information of the near-surface characteristics which can be used to better constrain the first-break inversion.

The first step of the workflow starts with the surface wave dispersion curve picking. As reliability of the results directly depends on the quality of that picking, data regularization are used to improve picks accuracy on both low and high frequency of the phase velocity/frequency spectra. A surface wave tomography process is then applied to convert the spatially irregular frequency-dependent picks into a regularized (x, y, frequency) Rayleigh wave’s velocity volume. Lastly a laterally constrained depth inversion is performed, delivering a 3D shear wave’s near-surface depth velocity model.

The second step of this workflow uses this S-wave velocity model, which contains the near-surface details captured by the Surface-Waves, to constrain the refracted P-wave first-break tomography. A regional scaling, here a 1D VP/VS ratio estimated from knowledge over the area or from fast-track refraction first-break analysis, is required to convert the S-wave velocity into a P-wave model. The constrained tomography aims to scale the trend from the high-resolution S-waves velocity model by fitting it with the trend of the P-wave field derived from the first arrivals. This corresponds in a sense in inverting the VP/VS ratio in such a way to preserve the high-resolution feature scaptured by the surface waves while remaining consistent with P-wave information. The resulting near-surface velocity model looks more geologic, better respects P-wave travel times and can be used with more confidence to compute the primary statics solution than the conventional P-wave field only obtained from the first-arrivals tomography…

Furthermore, this accurate update of VP/VS ratio can be used to estimate the Poison’s ratio. It can be used to better plan geotechnical survey in order to reduce shallow drilling hazards.
An Innovative Approach of Nuclear Magnetic Resonance 2D-T1T2 to Identify Complex Reservoir Fluid Regime of Gas-Condensate in Newly Discovered & Fast Appraisal Carbonate Reservoir Field of Abu Dhabi, UAE.
Authors: Singh Maniesh , Bankole Ibukun , Aldahmani Asma , Alzeyoudi Mona , Hajri Zaher Al , Bahri Sami El , Ahmad Mula Nur , Balliet Ron , Vican Kresimir , Jambunathan Venkat
Published: November 2017

This paper covers a case study of successfully applying innovative NMR logging technology for fluid typing using continuous measurement from longitudinal and transverse relaxation two dimensional (2D) maps (2D T1T2app), helped in reducing fluid typing uncertainty in different clusters of one of the recent discovered gas-condensate Cretaceous stacked carbonate reservoirs of Abu Dhabi field.

Generally, the reservoir fluid type in gas-condensate reservoir is confirmed by observing a representative fluid sample in laboratory, but at times collecting representative sample becomes challenging especially in tighter formations or unstable wells or rugose holes.

The advanced logging techniques, such as Nuclear Magnetic Resonance (NMR) and Downhole Wireline Formation Testers (FT) with pump-out fluid sensors, can be extremely beneficial in resolving fluid types in downhole reservoir condition for such complex fluid regimes and is also applied in this recently discovered carbonate field. NMR continuous T1T2 (simultaneous longitudinal relaxation-T1 & transverse relaxation-T2) logging & 2D fluid characterization methods at closer interval have been very important and useful data to assist in differentiating condensate, gas, and water in each of the reservoir in the static condition. Free gas (methane) occupies a unique location in a 2D T1T2app map with a relatively long T1 and short T2 signature. Dead oils or low GOR oils typically have a low T1T2 ratio and condensates are identified by their fairly large T1T2 ratio. The fluid signatures from the 2D maps are then quantified to compute individual fluid volume for hydrocarbons and water. Reservoir fluid typing from NMR 2D T1T2app not only helped in optimizing formation tester PVT sample points, but was also found in agreement with fluid analysis results from formation tester sensors where reservoir fluids were sampled from a greater distance from wellbore after longer duration of pump-out period.

The NMR Fluid typing using 2D-T1T2 app has helped identifying gas-condensate-water fluid types in static condition before sampling or testing. This has helped to understand regional fluid distribution in tighter reservoirs especially where fluid gradient has not helped due to unreliable formation pressure data.

By applying NMR fluid typing in difficult gas-condensate fluid regime validated further by fluid sampling and testing, has provided confidence in placing perforation at correct depth for testing, improving regional fluid distribution and bringing timely value to optimize engineering techniques for fast track appraisal & development program.
Environmental Leadership through Flare Optimization and Operations Excellence
Authors: Mukhamedkali Shynggys
Published: November 2017

The objective of this paper is to describe innovative process and tool developed for gas flaring reduction through Plant Optimization in order to meet state regulations.

According to Republic of Kazakhstan Laws, flaring of any substances during oil & gas operational activities needs to be logged and reported. Kashagan Field facilities are extensive, using approximately 260 valves connected to 2 Onshore and 3 Offshore Flare stacks

Over a reporting period, a valve can be opened and closed multiple times. Based on characteristics of the valve (valve type, pressure differences, valve opening percentage), the volume can be estimated for each release of gas (i.e. Flaring Event).

The following are the challenges that NCOC faces during flaring: Reasons for a flaring event need to be captured and the flaring events need to be managed to properly report the Flaring data against license constraints.Estimated volumes should be reconciled with calibrated measurements of total (at Flare Stack) flare volume taken from calibrated meters, entered in Hydrocarbon Accounting System (Tieto EC System).Composition needs to be derived from flare gas sources (valves).

Temperature and Pressure data to calculate Flaring Volumes are taken from Real-time Historian (OSIsoft PI System). This calculated data is reconciled against actual Flare meter value from EC. In the end, we have reconciled actual data for each valve to report to the Government bodies.

Flare events reporting is very critical for oil & gas business due to high environmental impact that costs North Caspian Operating Company N.V. (NCOC) considerable amount of money. Precision and accuracy of flare compositions reporting improves cost effectiveness. In future, this kind of analytics approach can be implemented for surveillance and reporting of another Oil & Gas operations outcome, water usage and disposal.
First Successful Logging Jobs Worldwide with a High-Resolution Logging-While-Drilling Imaging Tool for 8.5-in. Boreholes
Authors: Al-Balooshi M. , Anurag A. K. , Mishra A. K. , Al-Ali A. E. , Hosany K. I. , Al-Jefri G. M. , Sinha R. , Maeso C. J. , Girinathan S. , Legendre F. , Gzara K.
Published: November 2017

Borehole images constitute a rich source of high-resolution geological data about various formations penetrated by oil and gas wells. Interpretation techniques of these images have progressively improved over the years and provide detailed information about formation dips, structure, rock fabric, fractures, and drilling-induced borehole damage. Wireline tools have the flexibility to be used in a wide variety of borehole sizes. In contrast, logging-while-drilling(LWD) tools are designed for particular borehole sizes. A new high-resolution LWD imaging tool has been built for 8.5-in. boreholes. This paper presents the results from two logging runs located in offshore United Arab Emiratescarbonate fields, including the first worldwide logging run of the tool.

Measurements made by this new high-resolution imaging tool are based on laterolog principles for the measurement of resistivity. The tool performs two main types of measurements, including an array of focused resistivity measurements with an axial resolution near 1 in., and an ultrahigh-resolution resistivity imaging pad consisting of an array of eight buttons. This paper focuses on the LWD tool’s imaging section, designed to provide the same volume ofinvestigation as one of the focused resistivity measurements. This design featureresults in measurement calibration confidence with respect to the formation resistivity, allowing for quantifiable analysis of the formation properties using the image data. The data for this first run were acquired during a washdown through a carbonate-evaporite sequence. Borehole deviation was approximately 60° and the mud was a typical high-salinity water-base mud. A suite of wireline data, acquired after the LWD washdown run, includes a pad-based resistivity imaging tool, which allows comparison of thetwo sets of acquired data.

Data from both the wireline and new high-resolution imaging LWD tools were processed and interpreted. Structural and cross-bedded layers were clearly visible on both imaging-type tools. Borehole crossing and layer-bound fractures were also observed and could be quantified from both tools.

Examples show how identifying some featuresis made easier on the full borehole coverage of the LWD images; however, the higher resolution of the wireline tool is beneficial for identifying some textural features. Results from both types of logging tools are presented and the similarities and differences are summarized. Advances in borehole image visualization are also presented as 3D views in addition to cross-sectional views across the borehole, which make visualization of features more user friendly for those not familiar with borehole image interpretation.
Common Pitfalls in Selection of Restriction Orifice for Depressurization of Oil and Gas Facilities
Authors: Wasnik Rakesh , Singh Bhupinder , Singh Harendra , Kamal Faris , Takieddine Ousssama
Published: November 2017

Multi-stage restriction orifices are being increasingly used for Oil & Gas facilities depressurization instead of single stage orifices in order to overcome noise and vibration constraints. These are typically in the range of 0.5 to 3.0 m long considering 6-10 stages used particularly for high pressure depressurization system. However, in reality Multistage Orifices impose layout constraints in offshore installations and especially for congested brownfield modifications.

Multi-stage orifices are used in Gas and liquid service where large pressure drop is required to avoid choke flow condition and cavitation respectively. Multistage orifices help to eliminate noise, vibration in piping due to cavitation and choked flow. During depressurization of hydrocarbon inventory, the flow through the restriction orifice is inherently in choked condition, thus restrict the relieving rate allowing optimized vent/flare system design. Noise and vibration resulting from choked flow conditions can be addressed by piping design or selecting single stage multibore restriction orifice and thereby eliminating the use of a multistage restriction Orifice for depressurization.

Multi-stage restriction orifices are recommended by suppliers wherever pressure drop is exceeding the choked pressure ratio, which is usually the case in facilities depressurization. The number of orifice stages is selected for limiting pressure drop at each stage below the choked pressure ratio. However, multistage restriction orifices application in depressurization service imposes various challenges such as potential blockage in any of the stages due to hydrate formation and draining of residual fluid from the assembly considering its complex geometry. These challenges get aggravated especially for brownfield modifications wherein single stage orifices are replaced with relatively long multistage orifices in existing congested facilities. Single stage orifices fulfill the requirement of depressurization provided piping design addresses the noise and vibration. Even these requirements can be relaxed by considering intermittent nature of the operation and actual operating experience.

NPCC’s experience in many onshore/offshore oil and gas projects suggests that complex designs can be simplified based on better understanding of functional requirements of depressurization in consultation with suppliers. This paper discusses the constraints of installing multi-stage orifices in offshore installations based on examples from recent EPC projects and proposes to adopt simplified, safe and cost effective design. The paper also highlights benefits of conventional single stage orifices for depressurization service.
Main Automation Contractor Concept and Its Future Challenges
Authors: Gazi Islam , Al-Ali Hassan Ahmed , Al-Falahi Ahmed , Al-Shamsi Mohammad Hassan , Khanbooli Mohamed
Published: November 2017

Currently, Abu Dhabi Marine Operating Company (ADMA-OPCO) is developing three new fields. The respective projects or fields are named as A, B, C in subsequent sections of this paper. All three new fields have Main Automation Contractor (MAC) concept which means plant process control and safety systems are supplied by single manufacturer. This paper presents the difference in MAC concept between these projects and proposes an extended MAC Scheme which covers the electrical control system also in MAC scope. The authors predict that merger of process and electrical control system along with most of the subsystems (Packages) into a unified network will be the trend for future green field projects. The paper describes the technical and commercial advantages the proposed scheme can have over conventional MAC philosophy. A section of the paper also highlights the challenges associated for implementation of the proposed architecture.
Underground Storage of Hydrocarbons: Advantages, Lessons Learnt and Way Forward
Authors: Londe L.
Published: November 2017

Underground hydrocarbon storage is a mature technology, born in the early 20th century and very widespread today. The success of this technology lies in its economic efficiency, its safety and, ultimately, its excellent environmental track record.

The market is divided among three techniques: (1) storage in porous media, by far the most widespread technique for storing natural gas; (2) storage in salt caverns, a technique that is suitable for all hydrocarbons; and (3) storage in mined caverns, a technique that is used for liquid or liquefied products.

The market is currently changing. Underground storage facilities are under increasing stress from operators that are seeking to obtain the most from them. Although some storage facilities still have few movements, since they are used for strategic reserves, many storage facilities today have to provide an optimised working volume and higher cycling and deliverability rates than those for which they were created. Monitoring and modelling are helping designers of storage facilities to improve their efficiency. Safety enhancements are the second mechanism by which underground storage facilities are currently being upgraded. This involves design improvements, with the addition of new safety equipment such as fail-safe valves. It also includes the implementation of best practices. Therefore, tools are available that comply with regulatory requirements and meet the economic efficiency needs of storage facilities. The storage facility integrity management system is one of these tools. Diagnosis and tracking of induced seismicity is another example.
Processing and Recycling Drill Cuttings at Source - Technology and Services Adhering to Zero Discharge Legislation
Authors: Pond Robbie , Hinden Pierre-Marie
Published: November 2017

This SPE paper describes ZADCO's reasoning foropting to utilisethe TCC RotoMill® as the proprietary technology at the core of ESNAAD-TWMA's integrated drilling waste management services on the four UZ750k artificial islands in Abu Dhabi. It outlinesthe basis for this conclusion after examining the drilling programme, well profiles and volume of material that would be generated across the long-term drilling campaign. It also outlineshow they could optimizetheir drilling programmes whilst complying with and exceeding regulations outlined by ADNOCthrough the use of this technology.

The paper explains the TCC RotoMill® technology, its fundamental operating parameters and capabilities which areillustrated in the final presentation of data fromthis case study and the field results from this project. The background and evolution of the TCC RotoMill® is detailed from its origins of being created in conjunction with an International Oil Major ahead of regulatory change in the UK (OSPAR convention). The paper will illustrate the evolution of the technology to modern day units offeringthroughput of up to 10Mt per hour of NAF drill cuttings in onshore / offshore locations and latterly, being adopted as a mobile technology servicing the land rig market.

Lastly, the paper outlines the application of this technology on the UZ750k four artificial islands as an integral part of the larger scope of drilling waste management which collects, transfers and contains all of the drilling returns prior to treatment and/or disposal. The solution was developed whereby drill cuttings are contained and treated at source, enabling ZADCO tomeet and exceed legislative parameters. This eliminated the requirement for ZADCO to transport a significant amount of drilling returns offsite, thereby significantly reducing logistics costs and likelihood of environmental or safety incidents.

The success of the project is summarized in the case study data and key facts which outlines the value added benefits of collecting, transferring, storing and processing 1,443,029 bbl. (volumes to date) of drilling returns with no material having to be transferred offsite and sailed via a supply vessel onshore saving approx. 532,896 km of shipping.

By returning base oil to the Company, TWMA has saved ZADCO approximately $12.7m in recovered base oil across the four islands (which is extracted from the drill cuttings using the TCC RotoMill®and transferred back to ZADCO.)
Evaluating Performance of Foam-Assisted Lift in Sultanate of Oman by Dedicated Field Testing
Authors: Veeken Kees , Hinai Khalid , Shanfari Abdul Aziz , Yamadi Ahmed , Zadjali Abdullah , Saidi Ali , Hadhrami Hatim , Daraai Thabit , Mans Jeroen , Yousfi Idrees , Hinai Hisham , Wahaibi Yousuf , Musalami Khamis , Medhi Rawa , McIntyre Neil , Kindi Ahmed , Kindi Osama , Naabi Hajer , Mabsali Laila , Dhahri Hisham
Published: November 2017

Foam-assisted lift (FAL) is a well-established gas well deliquification technique to prolonge stable production from depleting, liquid loading gas wells. Field tests were carried out to delineate the operating envelope of FAL in PDO liquid loading gas wells. The field tests in five different wells consisted of step-down tests with and without continuous downhole injection of liquid foamer, to establish the associated reduction of the minimum stable gas rate. At the same time, the produced fluids were sampled and analyzed to diagnose potential impact on surface processing. The step-down tests were carried out using five different foamers that passed screening based on laboratory testing. FAL reduced the minimum stable rate by more than 40% independent of water cut i.e. for BS&W ranging between 14% and 96%. The step-down procedure required a surface choke which resulted in a significant reduction of the minimum stable gas rate, independent of the application of FAL.
Joint Inversion Facies Seismic Inversion to Delineate Thin Multi Layered Heterogeneous Reservoirs Offshore Abu Dhabi
Authors: Goraya Yassar , Bale Sean , Waters Kester , Sams Mark , Khalifa al Nemaimi Ahmed , Al Felasi Ali , Khemissa Hocine , Akram Fazeel , Al-Dhafari Bader
Published: November 2017

Today, the major challenge in reservoir management is improving reservoir characterization to better understand variations in rock properties and distribution of fluids away from the wells. A further challenge is the proper characterziation of thin multi-layered heterogeneous reservoirs. In this paper we present a new workflow to delineate reservoirs at and below seismic resolution.

A reservoir characterization study is performed for the Reservoir Z of the Giant field. The reservoir seqeuce consists of multiple reservoir units (1, 2, and 3) with variable average porosities between 11 and 28%. The study attempts to delineate separate units through an innovative Bayesian inversion technique that jointly solves for impedances and facies (Kemper and Gunning, 2014). Four different seismic facies were determined through an inversion feasibility study from variations in mineralogy and porosity. Elastic property trends as a function of time were built from the petrophysics of two wells. The low frequency component was driven by these trends and prior facies distributions were specified to constrain the results to be geologically reasonable. Three angle stacks were simultaneously inverted using extracted wavelets, each with specified noise estimates. An inversion was run using this technique on post stack data, as well as a coloured inversion for comparison.

Despite varaible data quality, the pre-stack facies based Bayesian inversion was able to invert for three separate layers of high porosity in the reservoir sequence in a number of blind wells. This was a noteable improvement on both the coloured inversion and post-stack inversion. It was concluded that the higher frequenices in the near stack data combined with increased rock physics contraints of the inversion resulted in better thin layer detection.
Produced Water Analysis by X-Ray Fluorescence with and without the Presence of Crude Oil
Authors: Yan C. , Guraieb P. , Ghorbani N. , Tomson R. C. , Abdallah D. , Aouda A. Ben , Odeh N. M. , Al Daghar T. A.
Published: November 2017

Scaling and corrosion are two common problems during oil and gas production which can cause severe safety issues and significant decrease in production. Analysis of produced water is widely applied to evaluate scaling and corrosion by monitoring parameters such as pH, alkalinity, cation concentrations, sulfate concentration, total dissolved solids (TDS) and conductivity/resistivity. Produced water sampling is usually performed at the wellhead for on-shore wells and can be done relatively easily if unpressurized samples are required. However, temperature and pressure drop as well as CO2 degassing during sampling dramatically affect pH and alkalinity measurements. As a result, carbonate scales may precipitate during degassing. For offshore wells, produced water sampling on site is costly and time consuming and mainly performed after abnormal observation of production rate. Thus, scale monitoring and prediction based on analysis of surface produced water is not reliable and analysis under temperature and pressure is required for accurate results.

In this paper, X-ray fluorescence (XRF) is used for monitoring water composition for scale and corrosion prediction with or without the presence of crude oil. To our best knowledge, XRF has not been reported as an analytical approach for water analysis with the presence of crude oil. This technique measures various metal cation concentration quantitatively in oil and water emulsions. It allows for a fast analysis of the water composition without the need for oil and water separation. Combined with automatic water analysis device developed previously, all important water parameters including, but not limited to, pH, alkalinity, sulfate, total hardness, TDS and cation concentrations can be measured for scale and corrosion monitoring and prediction. Measured results will be transfered and automatically incorporated into scale prediction software for scaling risk evaluation and scale inhibitor selection.

In addition, concentration of other metal ions (Na, Mg, Fe, Mo, Ni, Co, Mn, etc.), heavy metal ions (Pb, Zr, Hg, Cd, etc.) and nonmetal elements (S, P, As, etc.) can also be measured. Concentration of Fe, Mo, Ni, Co and Mn has been accurately measured. In situ measurement of transition metal concentrations can be a useful tool for monitoring potential corrosion during production.

The technology developed in this paper allows for automatic online monitoring of scale and corrosion risks under real production conditions. This system accurately measures various parameters and provides valuable produced water information without user interferences and with little maintenance.
Treatment of Produced Polymer-Containing Water with a Water Treatment Pilot Unit in the Matzen Field, Austria
Authors: Leitenmueller Verena , Wenzina Johannes , Kadnar Rainer , Jamek Karl , Hofstaetter Herbert
Published: November 2017

Nowadays, the injection of dilute hydrolyzed polyacrylamide (HPAM) solutions after water flooding operations is a promising tertiary recovery method. However, the treatment of produced water containing breakthrough polymer plays a challenging aspect in the oil and gas industry. Ensuring good filterability of the produced water for further usage, either pressure maintenance or EOR application, is still a critical issue. Polymer loads in the produced water need to be expected, which can massively influence the separation efficiency of the water treatment system. Especially, the handling of polymer-containing water streams and finding the appropriate technology for the treatment, chemically or mechanically, has a decisive influence on performing a full-field roll out of polymer flooding activities.

Aim of this work was to study the impact of back-produced polymer on the water treatment process and to reach the desired injection water quality. Therefore a water treatment plant in pilot scale was used. The unit simulates the main process steps of the water treatment plant Schönkirchen in the Vienna Basin (corrugated plate interceptor, dissolved gas flotation unit, and nutshell filter). The maximum back-produced polymer concentration, which can be handled within the system, was determined. Two different chemical sets (coagulant and flocculant) were tested, regarding their oil and solids removal ability, in presence of different polymer concentrations.

At the end of the field study, one of these chemical sets was found, having a hydrocarbon removal efficiency of around 99% in presence of 30 ppm HPAM inlet concentration. Using this set, good removal efficiency and no plugging of the nutshell filter was observed even at high polymer concentrations. The other set led to plugging of the filtration system at relative low polymer concentrations of 8 ppm HPAM and the removal efficiency of hydrocarbons as well as polymer was poor. Based on these results, it can be assumed that the processes of the water treatment plant Schönkirchen are not negatively affected in the presence of up to 30 ppm polymer load in the inlet water stream.
Study on the Classification and Formation Mechanism of Microscopic Remaining Oil in High Water Cut Stage Based on Machine Learning
Authors: Zhao Yuyun , Jiang Hanqiao , Li Junjian , Wang Chuan , Gao Yajun , Yu Fuwei , Su Hang
Published: November 2017

The formation mechanism and utilization conditions of the remaining oil in the high water cut period play significant roles in improved tapping potential and enhanced oil recovery. The classification of the remaining oil is a difficult point, meanwhile a burning issue. However, the current classification method is mainly through the manual method to determine the boundaries of classification, time-consuming and has a great subjectivity.

Machine learning and data mining methods in recent years have been widely used in the field of petroleum engineering, such as prediction of the recovery factor and so on, especially the well-known k-means classification algorithm.

The first objective of this paper is to use the semi-supervised learning (SSL) method to realize the classification of remaining oil in the high water cut period, based on the database obtained from experiments of 2D etched glass micro-model, with the help of the technique of quantitative characterization of pore structure and micro-residual oil. The method of principal component analysis (PCA) is used to reduce the dimension of the data. According to the formation causes, remaining oil can be divided into four types: oil film, throat retained oil, heterogeneous multi-pores oil and clustered oil. Two typical blocks are identified manually for each class, with an increased weight coefficients, then the other oil blocks with smaller weights are clustered into their types by the seeded k-means algorithm. The result shows that semi-supervised method is more effective than both supervised learning (with manual boundaries) and unsupervised learning methods.

Based on the classification, the effects on the formation of heterogeneous multi-pores oil and throat retained oil are analyzed by statistical method. All of these quantitative studies can provide theoretical guidance for the use of residual oil in high water cut periods and increased oil recovery.
Understanding the H2S Variations in the Upper Arab Formation in Abu Dhabi
Authors: Nederlof P. , Stearns S. , Kaczorowski N. , Lucas N.B. , Ghassan M.
Published: November 2017

The gas accumulations in the Upper Arab Formation in Abu Dhabi are characterized by tight reservoirs and highly variable H2S concentrations. The H2S concentrations range from 5 to 27%, without a clear vertical or lateral trend. With more than 10 reservoir units in the Upper Arab, it is practically impossible to test or take down-hole fluid samples in each individual reservoir. The exact gas compositions of large parts of the Upper Arab Formation therefore remain unknown. This paper describes a new approach to derive (sour) gas compositions from the geochemical analysis of rock samples, thereby enabling more detailed understanding of spatial fluid compositions. Subsequent integration with geologic and reservoir models will allow for more accurate predictions of the composition of future production streams.

In the tight reservoirs of the Upper Arab Formation, down-hole sampling requires long pumping times, during which (unknown quantities of) H2S will be lost to the drilling fluid. Well tests, on the other hand, tend to be short due to strict HSE regulations and stable flow cannot always be established before fluid samples are taken. Often, multiple reservoir zones are tested simultaneously averaging out any variability that exist between the individual zones. The limitations of the sampling techniques, together with the inherent fluid variabilities, create uncertainties for the reservoirs that have been sampled, while no information whatsoever is available from the reservoir units that have not been sampled. To address the uncertainty in reservoir fluid composition, we are developing geochemical technology that allows fluid compositions to be derived from core, sidewall core, and cuttings samples. Rock samples from gas reservoirs contain small amounts of adsorbed gas and condensate, which can be thermally extracted and analyzed. The extracted condensates are enriched in organo-sulfur compounds, which can be used as proxies for the Thermochemical Sulfate Reduction (TSR) reaction and thus for the H2S and CO2 contents of the reservoir fluid. The composition of the gas that was originally trapped in the pore space can thus be mapped away from the down-hole sampling points, also in reservoir units from which no fluids are available.

Based on available PVT data, the organo-sulfur compounds in the condensate and the carbon isotope ratios of the adsorbed gas, we were able to get some insight into the filling history of the Upper Arab reservoirs. Our data suggest that the TSR reaction that generates the H2S and CO2, is not an ‘in-situ’ process. Instead, the H2S and CO2 appear to migrate into the reservoirs with gradually increasing H2S concentrations, following the progress of the TSR reactions.
High-Resolution Porosity-Permeability Logs Driven by Macro-to-Nano Structures and PVT-Pyro-Geochemistry in a Middle East Unconventional Formation
Authors: Al-Shamali Adnan , Mishra P. K. , Verma Naveen K. , Quttainah Riyad , Al Jallad Osama , Grader Avrami , Walls Joel , Koronfol Safouh , Morcote Anyela
Published: November 2017

In Kuwait, the Najmah source rock is characterized by a complex diagenetic history and depositional variability. Accurate determination of the porosity and permeability logs is essential for improved petrophysical evaluation, which may not be properly performed using conventional methods. This complexity makes the conventional evaluation methods alone insufficient to determine porosity and permeability logs accurately. A major goal of this study was to produce high-resolution porosity-permeability logs for Najmah Formation using advanced digital analysis and geochemistry measurements.

Sixty (60) feet of continuous core were analyzed from an oil field in southwest Kuwait. The analysis started with dual-energy x-ray CT scanning of full-diameter whole core and core gamma logging. Plug-size samples were selected to represent the varying porosity and organic matter content along the entire core length. Two-dimensional Scanning Electron Microscopy (2D SEM) and three-dimensional Focused Ion Beam (3D FIB-SEM) images were acquired and analyzed to accurately determine the organic matter content and porosity. Matrix permeability was directly computed from the 3D FIB-SEM images using the Lattice Boltzmann method. The SEM porosity was calibrated by determining the amount of movable hydrocarbons at in-situ reservoir conditions based on geochemical analyses (XRF, XRD and LECO), pyrolysis indices, PVT data and adsorption isotherm experiments.

The digitally obtained porosity and permeability data showed a unique trend that was used to produce permeability at the core level. The integration between digital analysis and geochemistry data increased the estimated porosity and confirmed higher mobile hydrocarbon in the reservoir in comparison with the measured data at the surface. This produced a new porosity-permeability trend that was more representative of the reservoir conditions and caused a significant increase in the rock permeability.

The integration between the digital SEM analysis and the geochemical measurements was critical to estimate in-situ porosity and permeability characteristics of the tight formation under study. Moreover, this analysis provided an important tool for obtaining different high-resolution porosity and permeability logs based on various porosity considerations (effective, organic, inorganic, clay). This would lead to higher accuracy in determining reservoir properties for improved quantification of reserves and productivity.
Modeling Early Time Rate Decline in Unconventional Reservoirs Using Machine Learning Techniques
Authors: Vyas Aditya , Datta-Gupta Akhil , Mishra Srikanta
Published: November 2017

Decline curves are fast methods to predict production behavior in oil and gas wells. Some of the notable decline curve methods are Arp’s, SEDM (Stretched Exponential Decline Model), Duong’s Model and Weibull decline curves. Available production history data can be used to fit any of these equations and future production decline can thus be extrapolated. However, when limited production data is available during early periods of well history, these equations could be fitted using inaccurate parameters leading to erroneous predictions. Also, the traditional decline curve analysis approach does not account for the complexities related to reservoir description and well completions.

This study utilizes publicly available databases of the Eagle Ford formation to develop a novel predictive modeling methodology linking decline curve model parameters to well completion related variables that allows for the rapid generation of synthetic decline curves at potential new well locations. Modern machine learning algorithms such as Random Forests (RF), Support Vector Machines (SVM) and Multivariate Adaptive Regression Splines (MARS) can then be used to model the well decline behavior. Cross-Validation technique such as k-fold cross-validation can be used to quantify the predictive accuracy of these models when applied to new wells.

First, production data are fitted to decline curve models to estimate the corresponding model parameters. Next, machine learning models are built for these parameters as a function of initial flow rate, various well completion parameters (i.e., number of hydraulic fracture stages, completed lengths, proppant and fracturing fluid amounts) and well location/depth parameters (i.e., well latitudes, longitudes, total vertical depth of heel and difference between total vertical depths of heel and toe of horizontal wells). These models are used to rapidly predict the decline curves for new or existing wells without the need for costly reservoir simulators. It has been found that accurate prediction of rate decline of new wells can be predicted using this methodology. This method can also predict ultimate recovery of a new well based on data collected from previous wells.

To our knowledge, this is the first time machine learning algorithms have been used to predict the decline curve parameters and examine the relative performance of various decline curve models. The power and utility of our approach are demonstrated by successful prediction of the decline behavior of blind wells that were not incorporated in the analysis. We also examine the relative influences of various well design and location variables to determine the hidden correlations or interactions among them which are hard to decipher with other methods.