bluuebunny/crossref_metadata_2025_split huggingface dataset:
ADNOC Journey in Developing an Unified Value Assurance Process for Capital Investment Projects
Authors: Khalil Tariq , Balsubramanian Nagarajan , Lugon Patrick 
Published: November 2017

Abstract
The oil and gas industry performs significant investments in complex and risky environments to develop their Project portfolio.
To improve the efficiency of capital investments most of the Oil & Gas (O&G) companies assess the projects value by performing intermediate reviews before approving major milestones of a project that will authorize further investment.
ADNOC as many others was willing to improve capital efficiency and initiated its own process in 2014.
We will present in this paper the ADNOC journey in developing its Value Assurance Process for capital investment projects; how projects are classified, and how project reviews are set up upfront of the approval gates; the new Value Assurance Process put in place across upstream operating companies and key principles that will be applied for the development of opportunities.
Let us start the journey!
Modelling of Casing Reciprocation During Cement Displacement in ERD Wells
Authors: Sissenov Olzhas , Ruzhnikov Alexey 
Published: November 2017

Abstract
Ensuring a quality cement job when cementing long sections of casing in high angle, extended reach wells is both critical and challenging due to the high risk of channeling and pressure related issues. Casing reciprocation is intended to mitigate against channeling; however, this technique is not widely used in ERD wells in the industry. This paper presents modeling, operational observations, and the results of 10¾-in production casing reciprocation during cement displacement on several extended-reach drilling (ERD) well projects.
Accurate estimation of hydraulic lift force is one of the major challenges when planning casing reciprocation during cement displacement. The severity of the hydraulic lift force can cause the complete loss of slack-off weight when reciprocating on the down stroke, which is often perceived as the casing being "set" off-bottom. In order to accurately predict the hydraulic lift force and the associated hookload fluctuations, advanced modeling combining torque, drag, and hydraulics was developed. The model takes into account all of the key parameters such as slurries density and rheology, displacement rates, casing stroking speed, wellbore geometry, temperature and pressure effects, etc.
In excess of 10 casing reciprocation jobs during cement displacement have been successfully modeled and executed to date. The first several wells were used for model calibration, and the modeled loads for the remaining wells showed consistent and accurate predictions when compared with the measured loads during the cement displacement. The casing strings that were modeled and subsequently reciprocated during cement displacement varied in setting depths from 2000 to 3100 m MD, with the top of cement lifted to the previous casing shoe. It was observed that the effective hookload when stroking the casing down can significantly decrease when the hydraulic lift force is high due to the combined action of surge and circulating pressure. Slack-off hookloads were monitored in real time to determine cementing friction factors. The friction factor data allowed for calibrating the model, which gave confidence to continue reciprocating throughout the entire displacement until bumping the plug. The casing reciprocation campaign has contributed to an increase in the quality of the cement bond throughout the casing string, thereby no longer requiring any remedial cement jobs, which was a common requirement on the previous wells.
The technique and observations presented in this paper help close the gap that exists in the industry concerning the effect hydraulic lift force has on casing reciprocation operations. Understanding the effect is important in ERD wells, but can also be useful on other types of wells.
High Power Laser Technology in Downhole Applications, Reshaping the Industry
Authors: Batarseh Sameeh I. , Graves Ramona , Al Obaid Omar , Al Hartih Abdullah , Othman Haitham 
Published: November 2017

Abstract
This paper presents an innovative non-damaging technology as alternatives to current downhole conventional practices. It will change the industry and reshape several downhole applications such as perforations and fracturing among others. It is proven to provide not only non-damaging technology, but also improves flow properties and enhances communication between wellbore and formation.
For several years, researchers attempted to deploy high power laser technology for several downhole applications due to its accuracy, precision, control, consistency and power. The laser source is located at the surface on the coiled tubing unit, power generator provides power to the system and high energy is transmitted downhole via fiber optics cable to the targeted zone, the laser energy is manipulated and controlled through downhole laser tool to perforate and create tunnels connecting the wellbore with the hydrocarbon bearing formation. One of the main challenges is conveying the energy downhole with minimum loss through fiber optics. This paper will present the potential of the laser in reshaping the industry and change the current practices.
High power laser is proven to enhance flow properties in all types of rocks regardless their compressive strength and hardness, the unique features of the technology are the precision in controlling and orienting the energy in any directions regardless of the reservoir stress orientation and magnitude. It can be targeted directly to the pay zones and produce from bypassed zone that can't be achieved with current technology such as fracturing. Lasers provide safe, small footprints and environmentally friendly technology since it is a waterless base technology for connecting the wellbore with the formation (alternative to water base fracturing technology).
Hydraulic Study of a Horizontal Well to Compare Dual Horizontal-Vertical versus Single Vertical Completion
Authors: Alshmakhy Ahmed , Caicedo Sergio 
Published: November 2017

Abstract
With recent advancement of horizontal well drilling, longer wells have been drilled extensively. Initially, it was thought that when long wells are drilled, productivity would increase linearly. However, field experience proved otherwise. Many wells showed more production from heel side as witnessed by production surveys. The effect of introduced friction losses becomes significant when applied drawdown is closer to expected pressure losses making it difficult to produce away from heel. The objective of this work is to study the hydraulic flow aspects of a horizontal well in cases of single and two entry points.
A well, in an Abu Dhabi field, was equipped with a dual string in the horizontal section after a work over event to replace the standard single completion. The dual strings are separated by swellable packers and run so short string produces the upper segment while the long string produces the lower segment. Full hydraulic analysis is conduced to understand flow behaviour and associated pressure loses in both annular and tubing sections for both strings. A full scale of data gathering was executed including multi rate tests, production logging, and different flow setting with flow from strings separated and commingled at different choke settings.
Simulation cases have been developed to study flow from single standard tubing and dual, short and long strings, with theoretical and history matched scenarios. The resulted vertical lift performance curves are introduced to a coupled wellbore-reservoir model and production curves have been produced for various flow scenarios. This workflow provided a comprehensive method to choose the most appropriate method as an alternative horizontal well completion and demonstrated the value in terms of oil gain and water reduction as well as improved well accessibility.
The simulation study results showed an increased well productivity with multiple entry points, at heel and toe, especially with long wellbores in line with field results. In addition this alternative completion method allowed well accessibility and improved skin towards toe improving well productivity. Field results confirmed directional simulation results with more than 30% incremental production for each segment and full toe accessibility. This integrated approach provides a guideline on choke selection to confirm transport of produced fluids and mitigate issues with liquid hold up associated with production at high water cut.
The studied alternative method aims to encourage flow from both compartments of the wells with simple dual completion configuration versus the standard single completion. Application of this alternative completion method in early stages may be crucial to mitigate potential well issues that are difficult to cure later in well life. This paper provides a guideline using field cases and advanced coupled reservoir wellbore simulation to optimize well performance with cost effective techniques using currently available industry tools.
In situ Wettability Measurement in a Carbonate Reservoir Rock at High Temperature and Pressure
Authors: Alhammadi Amer M. , AlRatrout Ahmed , Bijeljic Branko , Blunt Martin J. 
Published: November 2017

Abstract
More than a trillion barrels of oil may be extracted from carbonate reservoirs in the Middle East. Oil recovery is known to be controlled by wettability (distribution of contact angles) that determines the pore-scale fluid configuration. However, these contact angles have not hitherto been measured in situ at reservoir conditions for reservoir rock that is saturated with formation brine and crude oil. We use high resolution X-ray imaging of a sample from a producing oil field to demonstrate that contact angles over a wide range are seen both above and below 90°. More than a million points of contact angle were measured after three pore volumes of formation brine flooding. The injected brine invades the center of the pores as a non-wetting phase leaving oil trapped in small pores and corners in connected layers.
Pores that were filled with initial formation brine remained water-wet. On the other hand, surfaces that were in direct contact with crude oil during aging were altered to oil-wet. However, water-wet surfaces were also measured in pores that were filled with crude oil which suggests that water layers in small pores, crevices, and within rock surface roughness, which might be connected to brine in micro-porosity, could prevent the contact between surface active polar compounds in the crude oil and the rock surfaces preventing strong wettability change. The reservoir rock became mixed-wet with a mean contact angle of 106° ± 20° obtained from 1.36 million in situ contact angle values measured using an automated algorithm (AlRatrout et al., 2017) applied on segmented three-dimensional X-ray image. The three-dimensional images were acquired using a high resolution X-ray micro-tomography scanner. The wetting condition resulted in a large volume of oil (50.6%) being trapped with a distinctive morphology as rough sheet-like layers.
CORAL 2.0: Forging Collaboration towards Industry Cost Competitiveness in Malaysia
Authors: Ali Hajejah , Mohamad Nurul Azni 
Published: November 2017

Abstract
Since early 2015, PETRONAS, through its Upstream Regulatory Unit (Malaysia Petroleum Management (MPM)) drives and coordinates an organized nationwide response to recent downturn of oil prices starting late 2014. Building on collective intelligence of the leaders from its Petroleum Arrangement Contractors (PACs), Oil and Gas Services and Equipment (OGSE) providers as well as PETRONAS’ internal organization, a cost optimization program, which termed as Cost Reduction Alliance (CORAL) 2.0 was defined to take Malaysian Upstream industry through a cost transformation journey, with the mission to optimize cost, improve efficiencies and drive innovation towards a new level of industry competitiveness. This paper documents the framework of this program and its key principles guiding the whole program execution. Several observations concerning its impact to Malaysian Upstream industry are also deliberated.
Sand Control Technology for Extended-Reach Wells: Best Practices from the Longest Gravel Packs Performed Offshore Brazil
Authors: Colbert F. C. , Costa A. L. , Gachet R. F. , Garcia F.M. , Neto A. T 
Published: November 2017

Abstract
The Campos basin is a sedimentary basin located in offshore Brazil, between the north coast of Rio de Janeiro State and the south coast of Espírito Santo State, encompassing many oilfields. Most of the reservoirs in the basin are high-permeability sandstones containing low API gravity oil but are without strong water drives. Long horizontal producer wells are the best economic option for field development but require water injection to maintain reservoir pressure. Horizontal sections generally range from 1000 to 2000m, which demands gravel pack as a sand control method. Gravel packing such long wells is a challenge and requires thoughtful engineering to optimize pumping techniques and technology. Presented here are best practices to overcome several challenges faced in this field to achieve overall success.
The challenge for extended-reach gravel packing is that the long horizontal section develops high friction during the alpha and beta wave propagation. Increasing the pumping pressure to overcome this friction increases the risk of fracturing the formation, consequently reducing the equivalent circulation rate downhole impairing the proppant transportation. In contrast, a reduced pump rate during alpha wave propagation can lead to a premature screenout due to the increase in dune height of over 85%. To overcome these issues and place gravel packs in these wells, careful engineering and simulation, lightweight proppants, friction reducers, and thorough job planning were used to successfully perform gravel packs in more than 40 horizontal wells completed in the Campos basin from 2011 up to 2017.
The experience of pumping the longest gravel pack jobs in offshore Brazil (horizontal length more than 2,000m) offer insights into best practices for gravel packs in extended-reach horizontal wells: Design considerations, specific well challenges faced, technologies deployed, and operational planning requirements. Specifically, highlighting the benefits of using lightweight proppants and optimized fluid systems to minimize screen out risks and maximize pack efficiency.
Alternative Framework for Structural Integrity Management of Jacket Platform Beyond its Design Life
Authors: Kongchang A. , Danthainum A. , Chattratichart T. , Sonachai P. , Thavornsuk T. , Katanyoowongcharoen S. , Sriparagul J. , Kosanunt P. 
Published: November 2017

Abstract
This paper presents an alternative to conventional approach where extended service life of an offshore structure is traditionally quantified by fatigue limit state. The paper provides Structure Integrity Management (SIM) framework relied on qualitative approach which determines prediction of extended life and optimised inspection strategy. The ultimate strength assessment is correspondingly deemed necessary to eliminate failure mode induced by fatigue crack. By which, the fitness-for-purpose of jacket structure with relatively low fatigue life can possibly be assured without the need of additional periodical level IV survey, degradation, modification and other functional mitigations.
Basic SIM framework is a cyclic process based on evaluation of original design and inspection findings throughout platform service life. A reassessment of existing structure is required after its original design life exceeded. The additional work process will be jointed to four main processes of SIM to refine the redundancy level. The prediction of extended life is determined using qualitative information in relation to nature of fatigue crack that rarely found on jacket structures installed since late 1980 in various locations around world.
Practical application of the alternative SIM framework is illustrated using an example of structures installed at 80 meters of water depth in Gulf of Thailand. The SIM program has been triggered since 2012 by essential operability beyond design life. Various refined levels of design approach could not provide extra service life due to change of metocean, and facility upgradation. It was thorough challenges to define a scheme which could present both acceptable risk level and optimised cycle. The ultimate strength assessment is carried out and it justifies survivability level on both intact and damage conditions of structures against environmental load at 1,000 to 10,000 years depending on their structural robustness. This higher level of assessment proves that low fatigue life joint of jacket structure does not significantly influence platform failure mode. The one-off level IV survey also confirms the irrelevance of fatigue. The qualitative extended life is predicted by this physical confirmation. The evaluation of SIM framework concludes that predicted life can be 2 to 3 times larger than original fatigue life.
The evaluation proved that fatigue does not influence to failure of existing offshore structure. The level IV survey to detail surface crack is not necessary over the period of extension. Unless, other initiators (i.e. anomalies, accident and etc.) require ad-hoc level IV survey. The level II and level III using FMD technique are only remaining part of inspection program.
Mechanical and Corrosion Performance of Corrosion Resistant Alloy Tubing after Long Term Use in Corrosive Gas Well
Authors: Suzuki Y. , Ueyama M. , Sagara M. , Amaya H. 
Published: November 2017

Abstract
For stable production of oil and gas, it is critically important to select appropriate OCTG materials suitable for each well condition. This selection is based on a combination of established material selection charts, know how, fit for purpose testing and life cycle costing. This paper provides and overview of the material selection process and details of the investigation results carried out on a CRA material exposed for a long term to a corrosive production environment.
For flow-wetted sections, the approach of material selection is substantially complex. Not only a thorough corrosion assessment based on the anticipated well conditions, but also selection of corrosion mitigation method using Life Cycle Analysis shall be considered. After that, a final material selection can be conducted.
Material selection was conducted for the harsh field and the selected material has been used for almost 15 years in actual H2S containing well. Investigations like mechanical properties, microstructure, corrosion resistance and surface passive film analysis were conducted.
Based on the well condition at the harsh field (CO2 = 115psi, H2S = 45psi, Bottom Hole Tmeperature = 104°C/220°F), UNS No. N08535 was selected.
7" Tubing of UNS No.N08535 with 110ksi grade has been used for almost 15 years in the above field, and retrived from the well.
The investigation carried out on the retrived material revealed that the amount and extent of sustained corrosion damage is virtually nil. The mechanical characteristics and the corrosion resistance are comparable with newly rolled material. These results indicating that the 15 years of down hole sour corrosive sevice had no negative effect on the material integrity.
In addition, surface analysis revealed that a thin sulfide film containing nickel and molybdenum was observed on the surface of the used pipe. This results well corresponds to the film formed on the specimen surface in the laboratory corrosion test under a simulated well condition, thus validating the fit for purpose corrosion testing approach usually applied when confronted to hostile environment applications.
This also validates the material selection process used and the integrity of UNS N08535-110ksi grade for this application.
This paper is the opportunity to access and analyze a CRA material which sustained long term exposure to a corrosive gas environment characterized by acid gas partial pressure of 115psi and 45psi H2S at a temeperature of 104°C/220°F
The Novelty of this paper is to show the performance stability of CRA during long term use under actual corrosive well condition and reliable selection for OCTG materials.
Optimization of Infill Development in a Highly Heterogeneous Giant Offshore Carbonate Reservoir
Authors: Kohata Akihiro , Willingham Thomas , Tiwari Anupam , Al Sowaidi Alunood 
Published: November 2017

Abstract
The subject field is a highly heterogeneous giant offshore reservoir. Current field development is predicated upon line drive water injection with 1 km spacing; however, it is anticipated that some oil will be bypassed due to geologic heterogeneity. In order to address the bypassed oil and improve recovery, a simulation study evaluating infill well potential for the target reservoir and an optimization of the full field development plan with infills was carried out.
This reservoir consists of two geologically similar areas which are a "Homogeneous" area and a "Heterogeneous" area. High permeability streaks (HKS) having ten times higher permeability than the matrix permeability are dominant in the Heterogeneous area while HKS are significantly less prevalent in the Homogeneous area. Two sector models which represent the Heterogeneous and the Homogeneous areas were generated and sensitivity simulations were carried out to evaluate the vertical and lateral placement of infills. Based on sector model findings, full field simulations were carried out to generate an optimized full field development plan with infills.
As a result of sector model simulation for the Heterogeneous area, infill wells showed higher recovery relative to the "No Infill" base case. Vertical and lateral well placement on infill location had little impact on the oil recovery. This is because the HKS in the upper layers were water-saturated by historical water injection from the base 1 km development; hence, water breakthrough at infill wells occurred from HKS within a short period of time wherever infills were drilled. For the Homogeneous area, infill wells showed slightly higher recovery but no oil plateau extension and high water production relative to the "No Infill" base case. Based on these findings it was concluded that (i) infills were required for Heterogeneous area and (ii) infill are not recommended for the Homogeneous area. For the full field evaluation, three different infill scenarios (i.e. 500m spacing infill implementation, 375m spacing infill implementation and no-infill implementation) were evaluated. The optimal infill development scheme for each pattern was chosen by comparing the production performance of each pattern of these three simulations. As a result, in the optimized infill case, infill wells were required primarily in the Heterogeneous area and were not required for the Homogeneous area.
Through this analysis, the impact of geological heterogeneity on the performance of infill wells and incremental oil recovery was assessed and the full field development plan was significantly improved. Based on these findings the resulting full-field development plan (i) minimizes the number of infill wells required, (ii) optimizes incremental oil production by addressing the bypassed oil.