bluuebunny/crossref_metadata_2025_split huggingface dataset:
Intelligent Digital Oilfield Implementation: Production Optimization Using North Kuwait Integrated Digital Oil Field NK KwIDF
Authors: Al-Subaiei Dalal , Al-Hamer Mohammad , Al-Zaidan Ahmed , Chetri Hom , Sami Nawaz Mohammad 
Published: November 2019

Abstract
Global oil demand has led to the development of new smarter drilling, completion, reservoir management technique and technology to optimize reservoirs production. The production of Kuwait Oil Company (KOC) has reached 3 MMBOPD and KOC’s 2030 vision is to boost the production to 4 MMBOPD. In order to achieve this vision, KOC has started several technical projects and development plans. One of these projects is the North Kuwait Integrated Digital Oil Field (NK-KwIDF) a full-fledged Field project implemented in KOC.
This Paper will discuss the scale, complexity, technology used, and advantage of using the NK-KwIDF. The North Kuwait (NK) asset has five fields, around twelve hundred active wells, and seven Gathering Centers (GCs). A complex network of pipeline, trunk line, and manifold are used to connect these twelve hundred wells to GCs. In order to optimize the production from NK every barrel of production opportunity has to be considered by optimizing suitable wells and minimizing downtime from each field, resulting the development of an extensive surface network model. The extensive surface network model takes into consideration of each and every details of field e.g. pipelines, manifolds, details of GCs and wells. For each and every well in NK assets a well model is prepared considering all PVT parameters, completions, and surface co-ordinate and finally connected to surface network model with all piping information.
Once the extensive surface model was prepared, several integrated workflows were developed in order to efficiently run the surface model and analyze the output from the run. Some of these workflows are ESP Optimization and ESP Analysis workflows, which have capability to identify the Oil Gain Opportunities and diagnose ESP performance. The identify opportunities are logged into ticketing system, which monitors the life cycle of the opportunity right from the identification till implementation into the field for Oil Gains.
The full-fledged development of NK-KwIDF took almost 3 years from the day it was started, as a pilot project with 133 wells. When an excellent result in terms of production optimization and downtime minimization was recorded from the pilot project, the pilot project was expanded to full-fledged field project. The NK-KwIDF project gave an outstanding result of Oil gain from well level as well as Network level optimization. It established an excellent reputation in the oil industry where it was a source of attraction for many NOC’s and IOC’s to visit and follow the flag ship for their development and implementation of digital field technology.
Case for Vertical Hydrocarbon Migration: Case Studies, Southeast Asia Tertiary Basins
Authors: Christopher Geovani 
Published: November 2019

Abstract
Complex hydrocarbon distributions where reservoirs are filled by oil and gas phases with different densities and genetic types interfingering within a basin are a common phenomenon in Southeast Asia and are often attributed to vertical migration. Attempts to understanding the controlling factors of vertical hydrocarbon migration by modeling the hydrocarbon charging and entrapment history from two Cenozoic basins in Southeast Asia—West Java and the Madura Platform—are discussed.
A modified invasion percolation algorithm was used to simulate the secondary migration models, which follows the principle that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. Three-dimensional (3D) seismic data were used as the base grid for migration simulation to capture the effect of both structure and facies variations on fluid flow.
Two models, one from the West Java Basin (fault-bounded structure) and the East Java Basin (nonfault-bounded structure), are presented. For both cases, interfingering between oil and gas occurred, with most oils trapped within the lower formations, a mixture of oil and gas dominates the middle formations, and mostly gas in the upper formation. These vertical arrangements are possible because of the relatively weak formational seals within the basin. For vertically distributed reservoirs, oil is often trapped within the lower interval, and gas is trapped at the upper interval. For a basin dominated by a vertical migration regime, the potential risk for hydrocarbon lateral travel far away from the kitchen is high, thus increasing the potential risk of prospectivity away from the kitchen. Understanding factors that help control vertical migration also help geologists better understand hydrocarbon distributions within the basins.
Case studies during which modeling helped determine the factors that influenced vertical hydrocarbon migration and the resulting potential phase distribution prospectivity risks in the studied basins are discussed.
Investigating the Chronic High Temperature Reading on the Lube Oil System of Water Injection Pumps
Authors: Alshaghab Hussain 
Published: November 2019

Abstract
Background: Almost all water injection pumps in our area are experiencing high temperature reading on lube oil feeding line to the bearings of disposal water injection pumps and motors especially during the summer season where it reaches 71.11 °C ESD Trip Point. The objective was to determine the root cause of this chronic problem and resolve the issue in order to avoid equipment trips as well as increasing the equipment availability. Method: Two methods were being conducted which are observing the lube oil temperature of leaving all bearings and analyze the lube temperature of each bearing outlet individually. The other method is by comparing temperatures measurements that were collected in the locations right after the (Temperature Control Valve) TCV and 1 meter away from the TCV every hour during the day time during summer season. Result: Statistics reveals that the temperature of the oil coming to the bearing is much less than 68.33 °C since some of the oil temperatures reading of oil leaving the bearings are less than 68.33 °C. Likewise, comparing temperatures measurements that were collected right after the TCV to reading collected 1 meter away from the TCV show approximately 10 °C difference in reading whereas the collected reading 1 meter away from the TCV is lower. Conclusion: the temperature sensors (one for the Hi switch, one for the Hi-Hi ESD switch and one for the TCV) are currently installed right after the (TCV). In this location, the liquid is still hot and heat transfer process between both hot and cold liquids is at the beginning phase and not completed yet. Therefore, above temperature sensors will always read the temperature of the hot lube oil especially during summer season from (11:00 a.m. to 3:00 p.m.), Hi-Hi Temperature ESD switch will be activated to trip the pump. This investigation concludes that the temperature sensors shall be re-relocated from the current location to downstream in order to provide time for the hot and cold liquids mix together. Benefits: The equipment availability will be increased as the unnecessary trips and unplanned downtime of the equipment are being avoided. Hence, it increases equipment MTBF. It also reduces number of warning alarms in control room which makes operators to focus in other issues. And most importantly that the reducing maintenance time and cost (approximately, USD 10,000 cost and five days’ work were avoided per each equipment). Example work that has been avoided to resolve the high temperature issue includes checking instrumentation healthiness, cleaning heat exchanger internally and externally, checking the fin-fan conditions, inpecting and testing TCV functionality, and inpecting lube oil tank as well as the piping which incudes the whole system.
Petrophysical Evaluation of Shale Gas Reservoirs: A Field Case Study of Marcellus Shale
Authors: Yildirim Levent Taylan , Wang John Yilin , Elsworth Derek 
Published: November 2019

Abstract
Successful petrophysical evaluation and stimulation treatments with horizontal drilling and hydraulic fracturing enable the economic development of shale gas reservoirs. Detailed evaluation of shale gas reservoirs before and after stimulation treatments is a prerequisite to increase efficiency and effectiveness of shale gas development. Determination of organic maturity, porosity and original gas in place remains a challenge using traditional petrophysical models due to the complex pore networks and ultra-low permeability of shale. On the basis of a petrophysical model for shale gas reservoirs (Passey et al., 2010), we propose an integrated approach for petrophysical evaluation using analyses of lithology, porosity, fluid saturation, organic maturity, geomechanical properties and initial gas in place.
Our petrophysical model for shale gas reservoirs is partitioned into organic matter, clay and non-clay minerals in the solids, adsorbed and free gas, together with capillary-bound, clay-bound and mobile water in the pore space. Vitrinite reflectance is computed in relation to the level of organic maturity (LOM) and kerogen density. Total organic carbon (TOC) is calculated using the Passey method (Passey et al., 1990). Effective porosity of shale gas reservoirs is calculated from algebraic expressions for solid and fluid fractions of the petrophysical model. Compressional and shear slowness logs are used to evaluate the geomechanical properties. Initial gas in place is calculated from free gas and adsorbed gas with porosity, fluid saturation, areal extent, thickness, adsorbed gas storage and organic matter.
The methods are successfully applied to a field case in Marcellus shale. TOC (wt.%) calculated by (sonic-density)/resistivity overlay methods for Marcellus Shale are 9.73% and 6.32%, respectively. TOC correlates directly to porosity and adsorbed gas in place occupied within the organic matter. For Marcellus shale, average density and sonic porosities are 6.25% and 3.46%, respectively. The comparison of Young's modulus and the minimum in-situ stress values between Marcellus shale and adjacent formations are used for the determination of the stimulation interval in the Marcellus Formation. Sonic and density logging suggest 2.22 BCF and 4.10 BCF as technically recoverable reserves with an 8% recovery factor. These results from Marcellus shale provide an improved understanding of economic development of unconventional reservoirs.
Innovative Use of Capillary String for Halite Cleanout in Sultanate of Oman
Authors: Veeken Cornelis , Alawi Ahmed , Ardia Kusela , Naabi Hajer , Janusz Norbert , Al Abri Ali , Ghanem Hassan , Fadhl Ahmed , Thakur Kapil 
Published: November 2019

Abstract
Following second stage depletion compression, more than 100 deep onshore gas wells operated by PDO in the Sultanate of Oman started suffering from downhole halite deposition. Halite scale blocks part of production and reduces well capacity by 20-80% depending on well specific conditions. Fresh water bullheading treatments were introduced to periodically dissolve the halite scale but in many cases treatments were applied too late or are not effective in preventing permanent blockage. In those cases, a cleanout using a work string is required to restore wellbore access and production. Historically, coiled tubing was used to remove halite scale via milling and fresh water jetting. Recently, 1/4" and 3/8" capillary strings were successfully deployed to reduce the cleanout cost and the volume of water lost to formation. This paper describes the experience with fresh water bulheading and the novel use of capillary string to clean wells that suffer from halite scale.
Removal of Condensate Banking from Different Formations Using Thermochemical Treatment
Authors: Al-Nakhli Ayman , Hassan Amjed , Mahmoud Mohamed , Al-Majed Abdulaziz 
Published: November 2019

Abstract
Condensate phenomenon occurs during gas production due to the reduction in reservoir pressure. In tight reservoirs, liquid banking causes an extreme damage and hydrocarbon production might be impaired due to liquid blockage. Therefore, stimulation treatments are applied to mitigate condensate damage and restore gas production. Several approaches are used to overcome liquid banking in gas condensate reservoirs. Gas recycling is one of the most effective techniques for mitigating condensate banking. However, at certain conditions, it might not be economical to use gas-cycling treatment, with the increasing demand on gas.
This work investigates thermochemical treatment to remove condensate blockage from different types of formation. In this work, rock samples from sandstone, shale and limestone formations were used. Thermochemical fluids that able to generate in-situ pressure and heat were used. Coreflooding tests were carried out by flooding rock samples with thermochemical fluids. Huff and Puff injection mode was applied to remove trapped condensate. Minimum of four cycles of injection and production phases were implemented. Sufficient soaking time was applied for all samples to ensure that the reaction between the injected fluids and the rock matrix reached to the equilibrium status. Pressure profiles were utilized to indicate the equilibrium status. The impact of formation type and number of injection cycles on the treatment performance were studied. The treatment efficiency was determined based on the volume of the removed condensate and the improvements of flow condition after the treatment.
The cumulative condensate recoveries were 72.97%, 68.09% and 43.38% for sandstone, limestone and shale samples, respectively. For all samples, the distribution of liquid recoveries with number of cycles are non-uniform. The incremental condensate recovery was reduced with production cycles, and more liquid removal was achieved during the first cycles of the chemical treatment. In addition, no formation damage was induced by the injected chemicals, which indicates that thermochemical fluids are compatible with the treated rocks. Reaction products of thermochemical treatment are able to stabilize the clay minerals and avoid clay swelling, particle migration and throat plugging. Overall, thermochemical treatment showed an effective performance in removing the condensate damage from limestone rocks. More than 60% of condensate banking can be removed using three cycles of thermochemical injection. In addition, the injected chemical showed minor effect on the rock integrity.
Successful Deployment of a New Intervention Technology Using a Reinforced, Flexible, High Pressure Hose; a World’s First
Authors: John Kevin Mathew , Morkved Marie L. , Grannes Ingvar , Haugvaldstad Jarle , Steinsholm Stian 
Published: November 2019

Abstract
This paper will discuss the design, qualification, testing and planning of a new intervention conveyance technology used to successfully remediate a failed down hole safety valve (DHSV).
The technology is a high pressure, reinforced, ¾ inch OD hose that is run on standard wireline equipment thereby reducing footprint, manning, cost and job time compared to other intervention methods. The hose has a working pressure of 12,500 psi with a tensile strength of 14,300 lbs. The system is gravity-fed into the well similar to a conventional wireline system and is spooled onto a wireline add-on drum with conventional wireline pressure control equipment (PCE). The difference compared to a standard wireline equipment is a modified add-on drum which includes a swivel for pumping, a purpose built stripper installed above the lubricator, and special inserts for the BOP.
Before mobilisation a series of tests were carried out to qualify the reinforced high pressure hose to ensure it was safe for interventions. Based on successful test results, the coil hose was mobilised and a total of 5 runs were carried out on the first job. These runs included jetting, spotting of chemicals and a caliper survey. The intervention successfully jetted 15% hydrochloric acid (HCl) over the DHSV, and through to surface. The job was an operational success and the DHSV inflow test, post treatment was successful.
The reinforced, high pressure coiled hose is a new conveyance technology that positions itself between wireline and coiled tubing. This technology can access wells on locations where running coiled tubing (CT) operations can be a challenge due to limited crane capacities and/or deck space. While coiled hose is not a replacement for CT due to its limited pumping rates (approx. 50lpm) and gravity feeding, it is suitable for spotting chemicals, N2 lifting and light cleanout operations.
An Innovative System Architecture for Real-Time Monitoring and Alarming for Cutting Transport in Oil Well Drilling
Authors: Selvaraju Senthil , Ramba Viswanth , Subbiha Senthilmurugan , Uppaluri Ramagopal , Dubey Pradeep Kumar , Musale Amol 
Published: November 2019

Abstract
A new system architecture is developed to provide decision aids on the prediction and prevention of downhole problems related to inadequate hole-cleaning and wellbore stability. The developed adoptive algorithm includes model calibration, real-time monitoring and alarm generation module when an anomaly is detected. An innovative approach is proposed to develop an unsteady state one-dimensional wellbore model, and model is capable do the real-time calculation of equivalent circulation density (ECD), and standpipe pressure drop (SPP).
The one-dimensional wellbore model is developed by integrating different sections of the mudflow. The unsteady one-dimensional wellbore model is integrated with Hershel-Bulkley model to predict both equivalent circulation density, and standpipe pressure drop (SPP), wherein the model parameter of the empirical equations are tuned to adapt to different types of rigs, mud systems, formations, and drilling scenarios. The mathematical model is first tuned with available historical data of the same well. Henceforth, the tuned model is used for monitoring the SPP and ECD profile across different sections of the wellbore.
The developed model is successfully tested in the oil field for real-time monitoring of ECD and SPP. The tuned model found to be capable of predicting the SPP below 5% error. The monitoring procedure of drilling activity was improved with a calibrated mathematical model. The system was able to detect the downhole problems related to hole-cleaning and hydraulic management, namely, excessive ECD, cutting accumulation in wellbore annulus and the possibility of stuck and kick in real-time. The false alarm generation due to sensor fault is found to be one of the challenging issues to resolve. Further, we observed that the data reconciliation and preprocessing of real-time sensor data could reduce false alarm for downhole complications. Further model accuracy can be improved by improving the accuracy of the sensors used for mud density, mud loss, and cutting size.
Unlike previous research works, in this work the annulus section of wellbore is divided into many small Continuous Stirred Tanks (CST) (i.e. Dynamic lumped parameter model) and they are connected in series to improve the accuracy of cutting transport model (i.e. to consider spatial variation of cutting concentration along the depth of the wellbore). Further simplified one-dimensional unsteady state wellbore model can be used for real-time calculation
Utilization of Artificial Neural Networking for Real-Time Oil Production Rate Estimation
Authors: Al Kadem Mohammad , Al Dabbous Mohammad , Al Mashhad Ali , Al Sadah Hassan 
Published: November 2019

Abstract
Oil flow rate testing is a crucial concept in oil fields where several methods facilitate well rate testing and measurement. Hundreds of multiphase flow meters (MPFMs) have been utilized to enhance the accuracy of testing measurement and provide reliable data for all fields. Even though these meters are of paramount importance, they require frequent preventive maintenance, calibration and manpower. In this paper, an Artificial Neural Network (ANN) model is developed as a backup tool to replace MPFM measurements when the device becomes defective or inoperable.
Several correlations have been established to facilitate oil well testing at minimal cost; relying on surface production parameters to allow enumerating the oil flow rate without installing expensive equipment. An ANN model was developed using real-time wellhead parameters measured from equipment installed at the surface to designate properties and characteristics per reservoir. The ANN model was calibrated, tested and validated to achieve the most accurate results. The model was further optimized to attain a reliable tool for real-time rate estimation.
In this paper, assessment of various correlations was conducted to compare the accuracy of each ANN-related empirical equation in five different datasets. The assessment also covers a wide range of data. More than thousands of data points from MPFM were compared to Towailib, Marhoun and Gilbert correlations, and showed highly deviated values with an average relative error of more than 40%. The same sets of data were tested using the newly developed optimized ANN model. The results from the model resulted in an average relative error of 3.7% compared with the MPFM rate measurements. Therefore, the new ANN model presented in this paper shows highly accurate results.
The developed model contributed to enhancing testing efficiency and optimizing production. Indeed, utilizing this model is an essential practice for production engineers to validate well tests if prompt outcomes are desired and another reliable tool to estimate real-time rate production when metering device is down.