bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wellbore Strengthening Geomechanics: An Engineering Design Workflow to Help Minimize Risk of Induced Lost Circulation
Authors: Savari Sharath , Van Beest Eric , Bonin Claudia , Guo Yonggui 
Published: October 2023

AbstractInduced lost circulation in depleted sandstone formations is a risk in most deepwater drilling operations, often leading to costly operational delays involving remedial treatments. Wellbore strengthening (WBS) using lost circulation material (LCM) to plug an estimated fracture width is one approach to minimizing this risk of lost circulation. However, most simulations for estimating fracture widths are either numerical or linear elastic models that do not account for wellbore inclination, azimuth, and different stresses.WBS planning involves fracture width estimation, which are kept propped open by LCMs. However, LCM blend selection is not often included in the wellbore strengthening workflow. In this work, a detailed field-friendly engineering workflow is presented that can estimate induced fracture widths accommodating wellbore inclination, azimuth, and different stresses around wellbore. The model also includes an LCM property referred to as "LCM blend stiffness," estimated using stress-strain data on different LCMs using a hydraulic press. The workflow accommodates varying LCM blends and, in turn, stiffness, to estimate maximum equivalent circulating density (ECD) providing wellbore wall and fracture-tip stability.The estimated fracture width from geomechanics-based WBS engineering model was first compared with the existing linear elastic model under the same conditions and results were within 10% variation. Using inputs from a major operator in Gulf of Mexico under the same conditions, the estimated induced fracture width was approximately 70% wider with the geomechanics based model that included wellbore inclination, azimuth and stress anisotropy compared to the current simple linear elastic model. LCM blends with different stiffness values were used as inputs into the model, and maximum ECD gain was estimated that provided both wellbore wall and fracture-tip stability. The analyses will also highlight the limitation with the model for due consideration in the solution selection. A geomechanics-based wellbore strengthening workflow is presented, which uses an analytical solution to uniquely solve for stresses around the wellbore with fractures, and a methodology for balancing wellbore wall and fracture-tip stability.The workflow aids in the selection of an optimal LCM combination that can provide maximum permissible ECD gain thereby stabilizing the wellbore wall (minimizing secondary fractures) and the fracture-tip (preventing fracture propagation). This is the first time that a geomechanics-based wellbore strengthening workflow accommodates LCM property and provides an estimation of fracture-tip stability.
Arthit Carbon Capture and Storage Project: The 1st CCS Implementation in Thailand
Authors: Kanokngam S. , Nitayaphan S. , Pulsawat M. , Sinthavarayan K. , Ngamlertsirichai N. , Nitipan T. , Rakpratanporn N. 
Published: October 2023

Carbon Capture and Storage (CCS) is one of PTTEP's strategic pathways for the energy transition movement to become a low-carbon organization with sustainable growth and to achieve Net Zero Greenhouse Gas emissions within 2050 with an interim goal of a 30% reduction in GHG intensity by 2030. It will hence support a reduction in industrial and domestic emissions under Thailand's commitment at the United Nations Framework Convention on Climate Change (UNFCCC)'s 26th session of the Conference of the Parties (COP26) to reach carbon neutrality by 2050 and net zero greenhouse gas emissions in 2065.
CCS is the process of capturing carbon dioxide (CO2) from industrial sources before it releases to the atmosphere and permanently storing it in an underground geological formation. The sequestrated carbon will be properly managed and monitored for total safety.
Successful Application of Solvent to Treat Condensate Banking in High Pressure, High Temperature Deep Tight Gas Reservoirs
Authors: Al Hinai Adnan S. , Al Amri Ghusun A. , Al Subhi Salim K. , Al Kharusi Dawood N. , Al Yaarabi Ahmed M. 
Published: October 2023

Abstract
Condensate banking is a common challenge in tight gas reservoirs as it reduces the gas production rates. Solvent treatment is a temporary solution, it revives the well, but condensate will keep accumulating until the well quits again. The paper aims at presenting the best stimulation practices for condensate banking, examples from two high condensate gas ratio fields in the Sultanate of Oman. With the intentions of how solvent technology increased efficiency post-completion clean out and how shut-in wells were revived to produce more than 50m3/d of condensate with good sustainability.
The paper summarizes the status of the field prior to implementing solvent treatment & the main challenges in the field, from the well intervention & production perspective. It also illustrates the technical selection & success criteria utilized to achieve the objectives. In addition, a brief explanation on the lab testing that was conducted prior to injecting the solvent into the well.
It was observed that the crestal and western-flank wells are mainly affected by condensate banking (CB) and the impact varies depending on the petrophysical properties of the wells. While the eastern flank has scaling issues and suspected crossflow.
Tight sandstones reservoirs were deemed not suitable unless the initial stimulation technique was hydraulic proppant fracturing. The target was to achieve a productivity index improvement between 1.5-2 times for condensate blocked wells and a minimum sustainability of 6 months.
Laboratory trials were prepared on core samples from five different wells with three experimental approaches. One of the experiments showed inconclusive results. Condensate Emulsions were discovered for the first time. As an extra gain from the solvent system, was the possibility to degrade such emulsion at bottom hole conditions but further testing required to understand the technical reason.
A well that was closed for almost twelve months initially produced condensate three times the expected rate for four months and had dropped by half and has been sustainable. Depending on the well condition, bull-heading the solvent can yield the same results as that of coil tubing, saving a good amount of cash. In-house customized solvent recipe showed a 66% reduction in cost per well.
The paper will add information in the current reservoir stimulation techniques buy providing the lessons learnt to sustain gas production from challenging environments such as Sultanate of Oman's Fakhar tight gas field. Modelling condensate banking phenomenon in a dynamic reservoir model will improve our understanding of the challenge, and how we tackle it.
The First Implementation of Shifting Sleeves Using Real-Time Hybrid Coiled Tubing with a Flow Through 360° Multi-Side View Camera, Kuwait
Authors: Khandelwal Nakul , Chawla Sapna , Travesso Joshua , Al-Kreebani Mohammed 
Published: October 2023

Abstract
The ABC field in North Kuwait is a high-potential field that poses challenges regarding hydrocarbon flow assurance through tight carbonate intervals with uneven reservoir quality and curtailed mobility. These conditions have shifted the field development from vertical to Multistage Frac (MSF) horizontal completions to cover the maximum reservoir surface and economically produce hydrocarbons from the field. With an influx of water in some wells, intervention is needed to selectively shut sleeves reliably in candidate wells.
Candidate well XYZ is completed with a MSF horizontal completion and an Electrical Submersible Pump (ESP) with a Y-tool to provide access to the lower completion. Real-Time Hybrid Coiled Tubing (RTHCT) with a Modular Sensing Bottom Hole Assembly (MSBHA) has become the preferred intervention method to manipulate sleeves in horizontal wells. To further increase the intervention reliability in real-time, a flow-through 360° Multi-Side View Camera (360 MSVC) is added to BHA to confirm the sleeve's opening and closing and optimize intervention time and operational efficiency by reducing the number of Coiled Tubing (CT) runs. The 360 MSVC is composed of four high-definition cameras with adjustable lighting.
The unique solution provided in this paper confirms the benefits of customizing RTHCT along with the MSBHA and 360 MSVC to open and close shifting sleeves. This approach saved more than 30 hrs of intervention time for the operator, helped reduce cost, and put the well on early production. The entire job was performed in a single run using real-time data from the MSBHA and 360 MSVC transmitted through the RTHCT. The MSBHA provided critical, real-time depth accuracy using the Casing Collar Locator (CCL) and Gamma Ray (GR), differential pressure for tool activation, and accurate load/tension values while opening and closing sleeves. The 360 MSVC provided real-time vision and confirmed the opening and closing of three sleeves. The total time taken to confirm the opening and closing of sleeves was reduced to 30 mins using the 360 MSVC compared to 12 hrs using Distributed Temperature Sensing (DTS). This intervention approach increased operational efficiency by reducing operational time and therefore cost, while the real-time visualization from the 360 MSVC confirmed operational success.
This entire job was performed rigless, and the well was immediately put on production once CT was pulled from the well.
The 360 MSVC provided a real-time downhole insight to aid the decision-making process and help achieve the operation's success. The operator saved on rig costs compared to similar jobs in the past, and the same procedures and technology can now be applied for upcoming wells in this field or any other locations globally.
A JetSweep Technology for Cleaning Under-Pressured Wellbores
Authors: Ahmed Al Hinai , Ibrahim Kamyani , Fathiya Rajaibi , Ameera Al Harrasi , Talal Nahwi , Ghadeer Kalbani , Mohammed Nahwi 
Published: October 2023

Abstract
To present the "JetSweep Technology" which is successfully applied to clean out the sand-filled due to the presence of loss circulations and sub-hydrostatic pressures in the horizontal wells in the south Sultanate of Oman. It represents a significant improvement over conventional rig/hoist cleanout operations, it is the latest advancement in JetSweep technology.
Sand production is big challenge in PDO. During conventional tubing cleanouts, significant losses at the reservoir is encountered. As a result, conventional cleanout operations using hoist pumps would not be able to lift-up the sands from the well hence this could lead to the work string stuck, which costs PDO a lot to recover the situation. JetSweep Technology were able to control the flow rate during cleanout and minimize losses, this helps to carry the sands from the well to surface. The major portion of the flow rate powers the jet sweep, which drives suction force, while the minor portion sweeps up the well by bypassing the isolation packer and driving fluid and sand to the surface while maintaining balanced pressure conditions. JetSweep Technology is able to clean wells from sand to the desired depths to un-plug the perforations for production restoration. This results on prolonging the performance of the production pump. Moreover, few interventions required over the well's lifecycle. Also, increases the well life cycle time, reduces replacement pump expenditures and deferments.
With JetSweep managed to shut off the water producing zone after cleaning and maximized the oil production. PDO successfully cleaned more than 210 wells and reduced oil deferment by US$16.38mln/year.
Additionally, before JetSweep, the wells used to be cleaned using Coil-Tubing Unit which is normally done between two mandatory hoist entries (preparing well for CTU and completing well). These activities now are substituted by single hoist entry in one-go using the JetSweep, this has resulted into additional saving of US$ 1.5 million per year subsequentially.
In summary, by using JetSweep, managed to:
Reduced cleanout operation times and pumped fluid volumes. Achieve full well bore oil production. Retrofitting wells with new wire-wrapped screens for sandy wells. Retrofitting with AICD/AICV to reduce water cuts.
Going forward, all wells with expected losses, JetSweep technology will be used with different applications:
Sand/Scale cleanout. Stimulation Acid lift-up. Post-Frac sand cleanout.
JetSweep technology is now seen as standard way of cleaning such wells from sand with losses during the clean-out. In PDO, it constitutes a game changer that is reducing the well life cycle costs, deferment and HSE exposure.
The global industry, where such challenges are present, PDO experience and learning would definitely help replicating the use of this technology to improve the efficiency of operating the wells during the depletion phases.
First Onshore DAS VSP in Abu Dhabi, A Complete Case Study, Onshore Abu Dhabi, UAE
Authors: Vargas Jose , Ofowena Frank , Ahmed Jahan , Bailey James 
Published: October 2023

Abstract
ADNOC Onshore tested the distributed acoustic sensing (DAS) Vertical Seismic Profile (VSP) technique in a well in an Onshore field in order to gain confidence and knowledge for future commercial DAS VSP applications. The main VSP objective was to assess data quality for VSP imaging and velocity information. The VSP test ran prior to an injection startup test, allowing the effect of injection noise on active VSP records to be studied. A walkaway (multi-offset) VSP design and Zero-Offset VSP were selected. The operation required good communication within a diverse discipline project team. The VSP operation was under constant assessment throughout. A daily QC process was executed as planned: enabling field data to be checked, to ensure quality and confirm operation decisions. One of the main project risks was the uncertainty of data quality concerning fiber coupling to formations. In this case the fiber was deployed behind the tubing, and prior examination of casing cement bond logs showed fiber coupling to formations was not guaranteed over the full length of the well.
CO2 Injectivity Test Proves the Concept of CCUS Field Development
Authors: Kaipov Y. , Theuveny B. , Maurya A. , Alawagi A. 
Published: October 2023

Abstract
The paper presents a unique case study on injectivity tests done in the Kingdom of Saudi Arabia to prove the concept of Carbon Capture, Utilization, and Sequestration (CCUS) capability. It describes the design of surface and downhole testing systems, lessons learned, and recommendations.
The energy company drilled appraisal wells to evaluate the multi-zone reservoirs with saline aquifers. The objectives of the injectivity test were to confirm the seal integrity (initial wells), reservoir injectivity, and surface injection pressure. The injectivity tests included the injection of water, N2, and CO2 at different regimes followed by fall-off after each phase. The Surface Testing System was used to pump and control the flow and measure the injection pressure and temperature. The Downhole Testing System is represented either by Monobore completion or DST where the downhole pressure and temperature measurements with wireless real-time telemetry are done at different depths.
The injectivity test brought great value in identifying and confirming the best reservoir for CO2 injection and defining the best completion strategy. Creating the injection conditions close to CCUS is vital, especially in heterogeneous carbonate reservoirs where the petrophysical correlations for the reservoir model require calibration with dynamic data.
The initial campaign consists of injecting the water up to frac pressure to confirm the seal integrity. Then, the water and N2 injection tests were done to determine the reservoir injectivity with different phases. These tests included injectivity profiling to evaluate the vertical heterogeneity. After an initial assessment of reservoir injectivity and selecting the reservoir for CCUS CO2 injection tests were conducted.
The CO2 injectivity test was challenged by the limited volume of CO2 tanks, its corrosive nature, and very low temperature. The surface and downhole system had to withstand these conditions and also the test duration should be optimized to get the representative pressure transient response for the available volume of CO2.
The downhole gauges provided the data for pressure transient interpretation during injection and fall-off periods. The real-time monitoring allowed us to interpret in real-time and optimize the test duration. The combining of multiple gauges at different depths allowed us to evaluate the friction losses in completion during high-rate injection and CO2 phase changes during the fall-off due heating effect. The CO2 injection creates an extreme cooling inside the well and this affected the downhole gauge behavior at certain conditions.
For the first time, the injectivity test with CO2 was completed at the appraisal well. Authors will provide the unique workflow, lessons learned and recommendations to the industry based on more than 10 wells with 4-6 individual injectivity tests.
ECO Development Procedure
Authors: Alhaji A. S. , Al-ghanem F. A. 
Published: October 2023

Abstract

Objectives/Scope
The objective of this abstract is to present The ECO Development Procedure, which is a quick and easy to adopt development tool that enables young engineers to attend their daily challenges through safe and robust procedure via securing a rewardable system that benefits both their seniors /specialists along with the young engineers in order to secure an efficient competency replacement policy in the team.

Methods, Procedures, Process
The ECO Development Procedure offers a unique competency development tool that can be utilized as a foundation for all Operational Teams competency replacement policy. The program methodology is based on operational procedures and utilizes the latest methods in training and development fields. Starting with utilizing the Power of Positivity in creating a non-judging or gradable procedure to equally award participants. Consultants and consultees shall practice Deep Listening, Power Questions, Smart Action-Items and effective feedback.

Results, Observations, Conclusions
The procedure was kicked-off with awareness sessions about its functionality and benefits followed by a recruitment campaign in one operational team as a pilot. Approximately (52%) of the selected pilot team engineers have volunteered and engaged in 10 focused training sessions extended over a period of 5 weeks. Satisfactory conclusion to the training session and feedback forms was secured and immediate implementation of the procedure was observed especially by newly joined engineers in the team. Further progression report was submitted to higher management and the next step development target has been set as an immediate next year Key Performance Indicator Item to the pilot team.

Novel/Additive Information
This newly developed procedure introduces a non-judgmental / positive platform that targets closing the competency gaps of daily task requirements between young engineers and their seniors / specialists via clear and easy to follow procedure that ensures the rights of development for young engineers. Nevertheless, maintaining the reward offered to seniors / specialists through official consultation records and satisfactory surveys ready to be presented in their yearly appraisals.
Developing Consistent Relative Permeability and Capillary Pressure Models for Reservoir Simulation of CCS Projects
Authors: Lun L. S. , Gao B. , Krishnamurthy P. , Kohli K. , Wattenbarger R. C. 
Published: October 2023

AbstractWith the need for rapid growth of the CCS industry, practitioners will need to rely on modeling and simulation, rather than analogs, to further understanding. We cannot solely rely on the results from the handful of small CCS projects around the world as the subsurface characterization of these projects have not necessarily been worked to the same rigor as major oil and gas assets. Furthermore, new practitioners are entering the space who may not be as steeped in subsurface knowledge and development experience as oil and gas professionals. We decided, given our history and leadership in both special core analysis (SCAL) and reservoir simulation to aid in developing and managing major subsurface projects, that we are in a unique position to give guidance to the CCS industry in this nascent phase. Presented here are a workflow to generate simulation-ready saturation function inputs (relative permeability and capillary pressure) curves and guidance on expected ranges for Corey parameters. We show that inputting measured data directly into a reservoir simulator leads to optimistic, underprediction of CO2 plume size during and post-injection, which has consequences to business decisions such as land acquisition, land stewardship and monitoring, measuring, and verification (MMV) plans.
Cost Optimization of Deferred Production Using New Rigless Technology
Authors: Abdullah Laila , Gilani Zubair , Jalan Shiv , Al-Naqi Ahmad , Al-Shammari Fawaz , Al-Rasheedi Kholoud 
Published: October 2023

Abstract
As the oil field matures the demand for artificial lift increases in order to sustain and boost production. Electrical submersible pump is one of the most commonly used method in oil industry. However, Conventional ESP deployment require Rig workover to install and retrieve the ESP Assembly, which is costly and time consuming. The conventional ESP applications have some challenges such as well accessibility for work over or well completed with 5″ or 5-1/2″ liner completions that required slim pump to fit inside the well. A novel rigless cable ESP technology is under development and pilot tests are in progress in Kuwait South and East fields. The technique utilizes Wireline method to deploy a slim pump type along with permanent magnetic motor system. The pump is capable of being deployed inside the production tubing within a short period without the need of a work over rig.
Rigless pumps tested in closed and failed ESP wells as pilot tests to restore the production until rig & equipment availability for permanent pump installation. The workflow started with well selection criteria to choose a well suitable and fit with the pump configurations. Then, performing well simulation to prepare the pump design parameter, followed by planning and implementing rigless surveillance jobs to insure well integrity and clearance. The deployment needs a slickline unit to set a packer inside the tubing, which is used as a seat for the pump also; wireline unit is required to install the pump through TEC Line (Tubing Encapsulated Cable).
The Technology was first time implemented at three wells as a pilot tests in East Kuwait area. It was successfully accomplished by installing Rigless ESP inside 3 ½" tubing through a Cable within 6-8 hours. The technology helped in avoiding using rig workover for installation, operation and retrieval. In addition, formation damage risks were avoided as no kill fluid was used.
The main objective of the cable deployed ESP was to reduce the short-term oil losses and to demonstrate the limitations and strength of the technology. Kuwait Oil Company saved rig cost as well as covered the cost of deferred production while waiting for rig to be available.