bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessment of Condensate Recovery Improvement Through Gas and Water Injection: A Case Study for a Large Heavily Depleted Very Rich Gas Condensate Field in the Sultanate of Oman
Authors: Cobanoglu M. , Shukri I. , Omairi R. 
Published: November 2018

Abstract
The Barik Deep clastic gas reservoir was discovered in 1991 and has been on production since 1994. It is a very rich gas condensate reservoir with initial Condensate to Gas Ratio (CGR) of 1100 m3/MMm3. With reservoir pressure dropping below dew point (428 bar vs. initial pressure of 478 bar), a huge volume of condensate has dropped-out inside the reservoir as confirmed by production data and the deterioration of well performance. As of 1/1/2018, the Barik Deep reservoir is developed with 29 gas producers out of which 7 wells are closed-in mainly due to liquid loading. The reservoir is currently producing above 2 MMm3/d of gas and ~400 m3/d of condensate and reservoir pressure is around 230 bars.
An integrated subsurface-surface study was started in 2017 with the objectives ∘To propose an integrated plan for re-developing the Barik Deep∘To identify solutions to maximize recovery of the dropped-out condensate∘To resolve condensate banking issues and its impact on productivity∘To identify new technologies allowing to increase production, to increase the field recovery (gas and condensate) and to propose a maturation plan for these technologies.
In a first phase of the project, a detailed analysis of all data collected over years of field development have been used to achieve a step enhancement in the understanding and characterization of the condensation process in Barik deep. In a second phase, the study involved the construction of compositional model capturing the physics of the condensation phenomena (i.e. very refined single well models) in order to assess various condensate recovery options. This effort supported the later building of full field simulation models to evaluate the impact of the most promising recovery techniques on recovery at field scale.
This paper covers: The interdisciplinary novel data analysis workflow approach followed to determine the critical elements of the condensation process (PVT, SCAL, pressure depletion, reservoir properties,...etc)The quantification and characterization of condensation by using analytical methods (Pressure Transient Analysis, PVT and production data analysis)The evaluation of various condensate recovery options (CO2, N2, separator gas, water injection and cyclic gas injection) using very refined single well physics based modelsThe evaluation of condensate recovery options using full field models adapted from these physics based modelsThe economical evaluation of condensate recovery optionsThe proposed road map for maturation of the most promising options
It is concluded from the conducted study work that out of the various injection fluid options considered, CO2 injection is likely to be the most favorable. Moreover, initial economical screening appear to be promising for CO2 injection.
Production Enhancement for Tight-Gas Condensate Reservoirs: A Compositional Dual-Porosity Model for Sabriyah Field, Kuwait
Authors: Al-Qahtani Misfera Misfer , Uzun Ilkay , Kazemi Hossein 
Published: November 2018

Abstract
A significant fraction of the world gas needs is supplied from gas-condensate reservoirs. The well productivity of these reservoirs is compromised because of liquid condensation in the matrix and fracture. The Sabriyah field is the first successful exploration in the North of Kuwait which led to the discovery of six extensive, deep, tight gas-condensate reservoirs. A purely fracture-dominated unconventional resource play, Najmah-Sarelu formation, is considered the source for most of the reservoirs in the Sabriyah field. In this paper, a compositional, multi-phase, dual-porosity model was used to analyze an existing horizontal well performance, and to evaluate potential enhancements to the future production.
The Sabriyah gas-condensate field in North of Kuwait is an abnormally high-pressure tight reservoir, which has very low matrix permeability and porosity. In this study, the geological system of Sabriyah field was studied using a static model to decipher the complexity of the reservoir—especially, the Najmah-Sarelu formation. A well's performance was analyzed using history-matching of the production data using a multi-component compositional dual-porosity model. To assess potential enhancement of the future production, eight different scenarios were studied. Specifically, we extended the current horizontal well length and added several multi-stage hydraulic fractures to increase production.
To assess the flow behavior of gas-condensate in Sabriyah field, we began with a study that tied the reservoir geology to the performance of a typical well using both static and dynamic simulation models. Both pressure build up and production data were analyzed using pressure and rate transient techniques which yielded an effective formation permeability of 0.5 to 0.6 mD. The numerical modeling parameters achieved a successful history match for one year of production, and the sensitivity analysis demonstrated that producing at a pressure of slightly below the dew point yielded the largest amount of condensate production. In particular, the additional condensate production was twenty-two percent for this case. Also, we observed that the existing horizontal well performed as effectively as having three-stage hydraulically fractured well in a matrix-dominated situation because of the presence of existing natural fractures replace the effect of the multi-stage fracturing.
Wellbore Assessment Using Time-Lapse LWD Calipers
Authors: Hamid Osman , Al-Qahtani Adel , Suaid Mohammed , Mohiuddin Mohammed A 
Published: November 2018

Abstract
Logging While Drilling (LWD) calipers (ultrasonic, density, and resistivity) have been available for several years, but their use is still limited due to the belief that they are not as reliable as the mechanical calipers obtained from wireline (WL) logs. One possible reason for this belief is the different time at which the LWD and WL measurements are made. In fact, LWD density derived calipers have their advantages over the WL calipers. One example is that they cover relatively larger portion of wellbore circumference, thereby providing a better characterization of borehole shape. A 3D caliper image can be obtained using 16 radii density measurements around the wellbore. Another advantage is that these measurements are available in real-time and borehole deterioration with time can be measured with time lapse acquisition. Accurate logging-while-drilling (LWD) borehole caliper data is important for drilling, logging and well completion. An accurate LWD caliper can greatly minimize risk and improve quality by bringing critical new information to these applications. During drilling, caliper data can be used to monitor the wellbore condition, providing early warning of borehole washout and impending wellbore instability, thus allowing the driller to take remedial action. During well completion, the caliper data can be used to accurately evaluate the volume of cement required to fill the casing annulus as well as aiding in the section of casing points or packer intervals by identifying in-gauge hole intervals. During logging, a reliable caliper is essential to correct some formation evaluation measurements for borehole size and to evaluate the quality of almost all LWD logs. A caliper can be used to plan services (such as formation testers) that may be affected by unfavorable borehole conditions.
In this paper, the main objective is to characterize the change in wellbore shape with time and relate it to formation characteristics and drilling and completion operations. Any relationship observed and correlated will be utilized to optimize these processes. The results presented in this paper show that the borehole degradation increases with time and that the accuracy of LWD derived caliper is 0.1in when both the LWD caliper and WL caliper runs are done at similar time periods. The depth of investigation in this case study is 2.25in.
Telemetry Managed Well Head Compressor: A Real Case Application
Authors: Cappuccio Pasquale , Imbò Pasquale , Gorini Simone 
Published: November 2018

Abstract
The GasJack® type compression units installed on wellheads are a widely applied solution to mature gas wells with unloading problems. These are very reliable machines for manned well sites, requiring little maintenance, equipped with appropriate safety systems. However, for unmanned platforms and remote areas, it is mandatory to improve the GasJack® units with a telemetry control system.
A dedicated R&D project has achieved such objective, through the following activities: "Feasibility Study", to evaluate the technical parameters and manned operations to include in the new system."Telemetry Technology Evaluation", to choose the most functional telemetry technology, by assessing the proper data communication system."GasJack® Unit Improvement", to identify the required modifications on the compressor unit, such as the replacement of existing components and the installation of a new control panel."Workshop Test and Certification", to certify the modified unit and verify its efficiency for the field test."Field Test", including an application in a remote and unmanned site, to restore production from a gas well.
The results obtained during the project are quite remarkable. The installation in the remote well area was successfully performed. At stable conditions, the technology demonstrated to be fully remotely manageable; telemetry confirmed to be an excellent tool for communication. The gas well restored its production and, thanks to the continuous monitoring and management of settings, the machine allowed the optimization and stabilization of the gas rate and liquid flow (doubling the well production capacity).
Therefore, the technology demonstrated that it can bring benefits in terms of wider application, well production increase, reduction of non-production time, simpler setting of parameters and unit operator costs minimization.
This paper explains how to update/modify a standard wellhead compressor unit, in order to install a telemetric remote control system and replace existing components, thus allowing use in unmanned sites.
A New Method to Model Fractured Rocks with Effective Capillary Pressure Curves and Saturation-Height Functions
Authors: Alobeidli A. , Li D. , Omura T. , Selvam B. , Al-Harbi M. , Ottinger G. , Obeta C. , Al-Shehhi B. H. 
Published: November 2018

Abstract
When a rock is fractured, its capillary pressure may radically change. In other words, the effective capillary pressure of the fractured rock is no longer the same as that of its original matrix. This is an important phenomenon to consider when building static and dynamic models of fractured reservoirs. Fracture capillary pressure can have a significant impact on modeling of initial water saturation. In a reservoir model, initial water saturation is typically calculated as a function of capillary pressure. While matrix capillary pressure can be obtained by measurements of core plugs, fracture capillary pressure is hardly known from actual data due to limited or no measurements from fractured cores. In this case, a practical solution to assign capillary pressure in a model is to modify the matrix capillary pressure in a reasonable manner. Generally, matrix of a tight (low porosity) rock can have very high capillary pressure, but once it is fractured, the water saturation in the fractured rock should be dramatically decreased. If we ignore this phenomenon, water saturation will be significantly over-estimated and consequently oil-in-place is under-estimated. Another impact of the incorrect capillary pressure can be on dynamic models, in which the model will show significantly early water breakthrough and dramatically higher water cut than field data. Therefore, correctly modeling fracture capillary pressure is critical for both static model building and dynamic model simulation. The proposed solution is to assign the effective capillary pressure for fractured rocks independently from non-fractured ones. The solution has been applied in a couple of giant carbonate offshore reservoirs in the United Arab Emirates and has demonstrated significant benefits in reservoir models with improved fluid stability and better water cut matches.
Unique Dual Core Acid Gas Removal Membrane Technology Reduces Total Cost of Ownership for South East Asia Gas Plant
Authors: Jariwala Ankur , Knight David , Mat Isa En M 
Published: November 2018

Abstract
Schlumberger has developed a unique PN-1 membrane technology in collaboration with Petronas. The technology is unique in combining two distinct types of membrane fibers in one single membrane module to reduce the overall membrane requirement by 10% and offers overall CAPEX and OPEX savings. The PN-1 technology was developed in 2009 and was successfully tested onshore and offshore facilities for total 5 years.
The PN-1 technology was first deployed in an onshore gas processing facility which was awarded to Schlumberger in 2013. The facility comprised of membrane pretreatment which is mainly gas dehydration, dew pointing followed by several PN-1 membranes in first stage. The membrane design was unique to handle variable inlet feed conditions from 25 to 12% CO2 inlet gas and outlet gas at 8% CO2. The feed gas design flowrate is 700 MMSCFD and at 750 psig operating pressure. Since this is an onshore gas receiving station, the processing trains should be able to handle variable inlet CO2 concentration in the inlet feed gas and particularly membranes.
Schlumberger engineered the entire pretreatment system, membrane and mercaptan removal system. The entire system was delivered and commissioned by Schlumberger on time and was brought online in 2017. The PN-1 membrane system was successful in meeting the required outlet gas CO2 specification while retaining maximum hydrocarbons in the product gas.
First Global Successful Large Diameter Pressurized Coring Application Using HPWBM: Kuwait Case History
Authors: Stewart Robin , Osman Tarek , Reda Tamer , Al-Ajmi Abdullah , Al-Rushoud Abdulaziz , Gohain Ashis , Khatib Faiz , Al-Haj Hussain , Al-Naqa Faisal , Al-Mutawa Faisal , Al-Gharib Majed , Shinde Hrishikesh , Al-Mekhalef Alanoud 
Published: November 2018

Abstract
Conventional coring does not provide core samples that are characteristic of the original formation condition. Thus, pressurized coring is required to capture samples that represent the in-situ composition of gases and liquids; pressure, volume, and temperature (PVT) data of the fluids, and porosity, permeability, and wettability, which are critical to reservoir interpretation and development. A customized high-performance water-based mud (HPWBM) was used successfully where prior attempts with conventional water-based mud (WBM) had failed.
The key well challenges included wellbore instability with caving shale and depleted reservoir sands. Previous attempts to retrieve pressurized core using conventional WBM proved unsuccessful because of the early activation of the pressurized capture mechanism caused by an accumulation of wellbore and mud solids linked to insufficient hole stability. A HPWBM containing liquid additives was customized to minimize solids content while stabilizing the shales and to minimize the differential sticking potential in the depleted reservoir. The formulation was finalized, based on laboratory testing, to optimize the bridging and inhibition package for the formations drilled.
Drilling and logging were successfully completed with no incidents; the fluids parameters were maintained to effectively clean the hole while controlling equivalent circulating density (ECD) through minimizing solids in the mud. The combination of salinity and liquid additives used minimized the total solids of the mud while effectively stabilizing the wellbore, which helped to reduce the premature activation tendency of the catcher system of the pressurized coring tool.
Pressurized cores were successfully retrieved with in-situ conditions and analyzed on-site, maintaining a pressure equivalent to the pore pressure. The core samples were retained in their native state for future studies. There was no nonproductive time (NPT) related to wellbore instability, and differential sticking was avoided by the customized bridging across the depleted reservoir. The successful collection of data enabled improved reservoir modeling.
This paper discusses the design of the HPWBM system, along with its technical features and benefits, which helped to successfully complete the first global 12 ¼-in. pressurized coring application. The customized HPWBM provided good shale inhibition, low solids and excellent lubricity, and eliminated the need for conventional shale stabilizing materials, which could have interfered with the capture of the pressurized core.
Improved Decision Making for Coiled Tubing Well Intervention With Downhole Video Camera DVC
Authors: Hamid Saad , AlMulhim Abdulrahman , AlGhamdi Abdullah , Unnikrishnan Vikram , Ahmed Usman 
Published: November 2018

Abstract
Conventional Coiled tubing well intervention has been carried out in oil and gas wells for more than 30 years with not real-time data acquisition. With the advent of Coiled Tubing Telemetry (CTT) e-line/fiber optics/mono conductors in coiled tubing industry, a wide variety of opportunities has become available - downhole video camera (DVC) being one of them, to go beyond the conventional parameters and optimize the well intervention operation.
DVC is used in the oil and gas industry with high success rate reported by several operating companies and service companies around the world. Video cameras have mostly been deployed using e-line; however, Coiled tubing camera runs provide the ability to clean the wellbore (by pumping fresh water or solvent) for capturing clearer, crisper videos and images.
As the oil and gas industry is moving towards improving operating efficiency, minimizing the coiled tubing runs based on actual downhole data is of utmost importance. Therefore, having the ability to inspect downhole obstructions using the video camera, and to observe the downhole conditions is phenomenal.
In this paper, the well intervention performed on multiple oil and gas wells in Middle East shall be discussed. Whenever an obstruction is encountered in the well bore, the primary form of detecting it is to run a lead impression block (LIB) on slickline or e-line. In most cases the LIB results do not provide a clear indication of the anomaly or obstruction. Not only that it sometimes adds to further confusion leading to inappropriate job design and planning, which results in potential misruns, inaccurate tool selection resulting in extensive and costly operations.
This paper aims to highlight the unique integration of DVC and telecoil application to enhance the reliability of data acquisition and job success. The custom designed downhole camera shroud, along with the robust CTT system is deployed in each of the candidate wells. The camera chosen is designed to withstand the maximum anticipated downhole temperature.
All the camera runs were analyzed and the obstruction in the wells was determined, which enabled the team of engineers to decide on the appropriate real-time course of action to gain access into the well bore or detect functionality of downhole jewelry.
Enhanced Gas Recovery by CO2 Injection and Sequestration: Effects of Temperature, Vertical and Horizontal Orientations on Dispersion Coefficient
Authors: Abba Muhammad Kabir , Abbas Abubakar Jibrin , Al-Otaibi Athari , Nasr Ghasem Ghavami 
Published: November 2018

Abstract
Enhanced gas recovery (EGR) by CO2 injection and sequestration is receiving increased attention within the research community. This is as a result of its potential to be an avenue for the simultaneous additional recovery of natural gas from the reservoir and provide a safe CO2 sequestration site. However, the major problem with this technology lies in the excessive mixing of the injected CO2 and the nascent natural gas (CH4) during the displacement process. This excessive mixing is the reason why the technology has not been widely patronised, given that the recovered CH4 will be heavily contaminated with the injected CO2 thereby making it "lacking" as sales gas after recovery. This hinders the market value of the recovered CH4 and eventually renders it not viable economically. Hence, highlighting the factors responsible for the mixing could provide technical solution to minimise the mixing phenomenon during EGR. This research focuses on the temperature effects and the orientation of the injection pattern of the technique. An experimental core flooding simulation was carried out at a temperature of 50°C and a pressure of 1300 psig and varying injection rates of 0.2 - 0.5 ml/min on Grey Berea sandstone core sample with the sample situated in both vertical and horizontal orientations. It was observed that at higher temperature (50°C) suitable for many gas reservoirs, the disperstion coefficient increased significantly compared to our earlier work (Abba, Abbas, & Nasr, 2017) at 40°C by a factor of 2.3. This trend was due to the increased energy of the gas molecules at the observed conditions, thereby increasing their mobilities. Conversely, the dispersion coefficient also increased significantly by a factor of 3.4 in the horizontal orientation at lower injection rates compared to the vertical core flooding with the concentration profiles showing significant capillary tailing effects at higher flowrates. This signified the effect of gravity in the horizontal orientation was more pronounced at lower injection rates during the injection of CO2 and this will have tremendous effect on the flow behavior of supercritical CO2 during the gas-gas displacement process.
Robust EOR Screening Workflow for a Carbonate Green Field: A Case Study
Authors: Ali Abdulla Ali , Park Sangseok , Mukhtar Muhammad , Ghorayeb Kassem , Alkhatib Mohamad , Ojha Aditiya , Shah Abdur Rahman , Ortiz Jaime Moreno 
Published: November 2018

Abstract
Early assessment of enhanced oil recovery (EOR) potential in fields that are at early development stages is becoming more common in the oil industry, ensuring that investment decisions are consistent with the EOR deployment once the field reaches maturity. Well, facilities and monitoring design maybe influenced to accommodate the EOR implementation, thus reducing Capex and mitigating project exposure. Challenges arise, as expected, due to the limited information, particularly when the field has not yet been under production and dynamic information of connectivity, compartmentalization and reservoir extend is scarce.
This paper describes the screening analysis performed on an onshore marginal green field in the UAE with four drilled wells and no production history with water injection considered on the approved development plan. The comprehensive screening workflow resulted on a narrow list of potential applicable EOR methods and their corresponding benefits allowing the operator to tailor development activities for early EOR de-risking and accelerated field deployment. A multi-dimensional approach was adopted using a combination of numerical, analytical methods and past EOR experience, to shortlist and rank the most attractive EOR development options, robustness of the selection (and ranking) was tested under the key reservoir uncertainties.
WAG was identified as one of the better suited EOR processes (complemented the planned waterflood) along with miscible CO2 injection (with possible WAG applications).
Resolution of Frequent Mechanical Seal Failure on Highly Critical Lean Solvent Pumps
Authors: Sharda Rajeev 
Published: November 2018

Abstract

Brief information of the issue
ADNOC Gas processing plant at Habshan 5, AbuDhabi was commissioned in 2013 and since then Lean solvent circulation pumps tag no 530/531/532/533P101A/B, which are highly critical to operations, remained bad actors due to frequent failures of cartridge mechanical seals.