bluuebunny/crossref_metadata_2025_split huggingface dataset:
Revisiting Subsalt Exploration Drilling Challenges
Authors: Alfayyadh Jaber , Al Moqbil Amal , Taher Ahmed 
Published: January 2020

The quest for hydrocarbons continues to increase and is becoming more challenging as the search pushes operators further into unexplored basins and frontiers globally. In the last 20 years, subsalt drilling has provided some new and promising prospect landscapes and fairways; however, major challenges are inherent with drilling subsalt exploration wells. One of the most problematic properties of salt is deformation or mobile behavior; in other words, salt has almost no permeability and porosity, and it creeps under differential stresses, causing hole stability issues.
Historically, where global offshore and onshore exploration frontiers encountered, salt drilling posed significant challenges to drilling. Because salt behavior is also attributable to salt type and the stress state of the confining geological environment, lateral forces from the rift ridge system and evaporite seal produce high mobility in the halite subsalt accumulations. Major challenges faced while drilling this salt were stuck pipe, tripping in and out issues, wellbore enlargement, and severe bottomhole assembly (BHA) whirl leading to catastrophic lost-in-hole incidents and nonproductive time.
In-depth analysis of the formation’s geomechanical attributes, mud properties, drilling practices, and casing design was fundamental to developing better defined and customized drilling solution strategies to address the unique subsalt drilling challenge. Drilling fluid selection, chemistry, and application engineering also played a fundamental role in preventing washed-out holes.
Additionally, the salt creeping rate is generally a function of in-situ stress, exposure time, and temperature. Proper mud design and drilling practice help minimize potential risks of hole instability in addition to modifying the casing design to isolate the salt, which requires a different mud weight than the overlying and underlying formations.
Most early exploration wells through salt were drilled as vertical wells; however, achieving the necessary directional trajectory control through a mobile salt caused concern. Therefore, potential geomechanical risks, drilling mechanic analysis, such as torque and drag, and potential vibration issues are considered while designing the directional path through a subsalt formation.
This paper discusses a comprehensive geomechanical overview, recent successful experiences of drilling salt with the application of drilling fluid, drilling practices, casing design, and trajectory design perspectives in addition to a comprehensive report of lessons learned.
Production Gains and Extended Electrical Submersible Pump Run Lives in Harsh Well Conditions
Authors: Camilleri Lawrence , El Gindy Mohammed , Kaci Yacine , Othmanine Mohamed 
Published: January 2020

Installing ESPs in a reservoir for the first time is always fraught with the uncertainty of achieving economic run lives and this is further amplified in harsh conditions. To mitigate the financial and production risks, sufficient production gains are required to overcome potential short ESP run lives. This paper discusses the results of four pilot ESP wells in Algeria and how infant mortality was eliminated in addition to achieving early production gains.
Key to achieving the production gains was candidate selection and well testing to confirm the well productivity and aquifer pressure support. This process also mitigated risk by selecting wells from a reservoir sector with a historical low incidence of asphaltenes and GORs, which have not spiked substantially above solution GOR. Once the ESPs were installed, the production gains were achieved by correctly managing drawdown through real time surveillance, which was also used to manage the stress on the ESP and avoid infant mortality. Longer term run lives was achieved by selecting the correct ESP materials and completion architecture for the well conditions.
At the time of writing this paper, none of the four ESPs had failed. The most recent installation had been running for 400 days and the oldest for over 1,300days, which is no small feat when one considers the harsh conditions; a reservoir depth of 10,500 ft TVD with a bottom hole temperature of 245 deg F and a volatile hydrocarbon (41 deg API) with a high GOR. This is compounded by an aquifer with water densities as high as 1.25 due to high salt content, which causes both corrosion and halite scale to form on a regular basis, which was treated with fresh water injection. In two of these wells, net oil production was doubled, but more importantly the recovery factor was substantially increased as the higher ESP drawdown mobilised reserves which would not have been produced with gas lift. Finally, the injection gas saved from converting two wells to ESP was sufficient to complete 4 to 5 new wells with gas lift completions.
In terms of technology, the main innovation was the use of an ESP digital twin to monitor ESP health in real time, which was particularly useful in managing the transients associated with slugging. An equally noteworthy take-away was how a holistic approach, which integrated reservoir, completions and production engineering provided seamless management from project definition all the way through to execution.
Liquid Film Mode for Prediction and Identification of Liquid Loading in Vertical Gas Wells
Authors: Landjobo Pagou Arnold , Wu Xiaodong 
Published: January 2020

Characterized as the reversal flow of liquid film into the wellbore, liquid loading is a genuine issue for gas wells as it diminishes the gas production rate. In the event that fluid rate accumulating in the wellbore is excessively high, the gas production rate will decrease fundamentally and for severe instances of accumulation, the operating organization will relinquish the well which will cause immense budgetary misfortunes. Subsequently, so as to maintain a strategic distance from the latter occurring, it is proper for the working organization to anticipate and recognize the liquid loading status of the gas wells in order to utilize viable apparatuses and pathways to avert it. Therefore, to counteract those misfortunes, the forecast of the liquid reversal point is obligatory.
Several researchers studied and established models to predict the loading phenomenon. After thoroughly review those studies, conclusions made on the different models are controversy and their results are conservatives. This paper presents a model where the hypothesis relies on fluid film reversal. The model considers the change from annular flow (fluid film encompassing the gas core) to slug or churn flow to be the grounds of liquid film backflow. Subsequently, from the review of previous literature on vertical wells, it is obvious that the film thickness is more sensitive to the tubing inner diameter, the tubing pressure gradient, the changes of fluid properties, the film and gas gravitational forces. Therefore, it is more rational for the critical gas flow rate to be dependent on those parameters. Subsequently, the momentum balances of both the liquid and gas phase were developed, and a derivation of an expression of the gas void fraction leading to the derivation of the dimensionless liquid film thickness and thus the critical film thickness were obtained. As a result of this modeling, a simplistic practical critical gas velocity and critical gas flow rate correlation which at the same time combines and incorporates the parameters influencing the loading phenomenon are viable for any profundity of the well.
So as to assess the adequacy of this model, evaluation has been performed between the model and some well-known model such as Turner et al. (1969) model, Li et al. (2001) model, Belfroid et al. (2008) model and Liu et al. (2018) model on some of the vertical gas wells of the North-West Xinjiang gas field. The outcome of this evaluation provides an overall 95% prediction and identification precision, outclassing the models quoted above. Thus, the model is the most appropriate to classify and foresee liquid backflow and accumulation in gas wells.
Efficient Joint 4D Seismic and Electromagnetic History Matching Using an Ensemble-Based Approach
Authors: Zhang Yanhui , Hoteit Ibrahim 
Published: January 2020

This study aims at enhancing reservoir characterization through simultaneous history matching of time-lapse seismic and electromagnetic (EM) data. We propose an efficient ensemble-based history-matching approach by exploiting the complementary nature of these data types.
The developed workflow consists of two main steps. Firstly, water saturation and porosity as the rock cross-properties relating to both seismic velocities and formation conductivity are estimated by joint inversion of seismic and EM data using an iterative ensemble smoother with an adaptive non-distance- based Kalman gain localization. Prescribed rock-physics models are used to quantify the corresponding relationship of rock properties to seismic velocities and formation conductivity, based on which synthetic EM and full-waveform seismic data are simulated. Secondly, instead of integrating the inverted saturation field directly, front positions are identified from the inverted saturation field and used as the observed data for history matching. Model parameters are conditioned to the observed fronts using the iterative ensemble smoother with a feature-oriented distance parameterization.
The approach is verified with synthetic data sets. Results show that joint inversion of seismic and EM data leads to better estimates of rock properties when compared with those from the separate inversion. Moreover, by integrating the extracted fronts from the improved estimation of the saturation field, which synthesizes the information from both types of data, the proposed approach significantly reduces the redundancy and number of data while still capturing the essential information. The novelty of the proposed approach consists in combining the feature-based history matching with ensemble-based geophysical inversion to achieve an efficient joint integration of time-lapse seismic and EM data.
Robust Chemical Dissolver for Reservoir Stimulation and Formation Damage Remediation
Authors: Panuganti Sai Ravindra , Misra Sanjay , Salleh Intan Khalida , M. Ibrahim Jamal Mohamad , Rodzali Mohamad Azmeer 
Published: January 2020

The process of matrix acidizing, despite being one of the oldest operations in the petroleum industry, is still a challenge for tight carbonate reservoirs. This project considers the development of a multi-functional environment friendly chemical, for reservoir stimulation and formation damage remediation.
A microemulsion solution of biodegradable chelating agent is formulated, which is effective for tight carbonate reservoir stimulation even at high temperature. Together with the chelate based inorganic dissolver, aromatic naphtha as an organic dissolver is the other main active ingredient in the proposed microemulsion formulation. For this reason, the microemulsion solution can also be used to treat inorganic and organic mixed deposits which can involve in formation damage. The developed multi-application chemical is later tested for compatibility with reservoir fluids and production chemicals encountered during well flow back.
Formulations with low reactivity are required when the injection of stimulant is not possible at high rate. By making microemulsion with chelate, the reactivity and diffusivity of the chelating agent can be controlled further. Core flooding experiments on core samples from high pressure, high temperature and tight carbonate formation, are conducted to demonstrate wormhole formation during the matrix acidizing treatment with the formulated microemulsion. The synthesized stable microemulsion chemical is also subjected for detailed dissolution study on deep wellbore deposits of different composition from different fields. These inorganic and organic mixed deposits are otherwise hard to be remediated by aqueous or organic solvent alone.
The novelty of this article is in developing a chelate based microemulsion as the main stimulation fluid. Another uniqueness of the microemulsion solution is in the treatment of formation damage causing deposit species which are mixed in nature, without the need of any additives.
Targeted-Acidizing Tech Meets Various Goals in Long Horizontal Wells: Enhance Productivity or Equilibrate Flow Profile
Authors: Xue Heng , He Enjie , He Bing , Kang Bo , Ye Jiexiao , Liu Fei , Mi Qiangbo , Cao Xianping , Liu Xue 
Published: January 2020

CT (coiled tubing) acidizing is the main work before horizontal wells put into production in the Middle East. The targeted stimulation interventions directly affect the afterwards performance of production and injection wells. This work not only highlights the importance of removing damage to enhance productivity of producer in the initial production stage, but also put forwards the effective measures of equilibrating flow profiles of injector and producer in the stable production stage.
The real-time acidizing techniques combined with distributed temperature sensing (DTS) is used to equilibrate inflow profile in injectors successfully. However, it is lack of effective measures or BHA to guide removing the un-uniform damage and improving acid absorbing in poor interval of horizontal producers. Combined with logging interpretation data and drilling parameters, a velocity-based un-uniform damage model is developed to understand the drilling fluid displacement, mixture and diffusion process in the reservoir-scale. To help ensure accurate acid placement in producer at different production stages, a targeted-acidizing idea is proposed based on the quantitative prediction of inflow and skin factor profiles. To compare the acidizing efficiency between various proposals and illustrate the effectiveness of targeted-acidizing design, A three-dimensional diverted-acidizing simulator is developed for carbonate reservoir, and applied in AHDEB Oilfield, Iraq.
According to the simulation of various acidizing designs in new producer, the acid placement based on skin factors can receive the highest productivity compared with traditional uniform, cone-shaped or permeability-based acidizing measures. In the case study, 3 typical acidizing targets cooperated with re-open work of producer have been proposed. The injection rate and acid volume have been optimized through simulation. In order to make under-stimulated intervals absorbing more acid and avoid connecting thief layers, the CT selective acid jetting plus drag back tech is introduced. The production performance after acidizing shows that the stimulation ratio reaches to 7 times. The water cut is also controlled very well.
It is difficult to enhance productivity and equilibrate flow profile at the same time under the limited acidizing scale, especially in the long horizontal wells (over 1000m). this paper highlights which goals we should consider firstly at different production stages, and give out the effective measures of evaluation and execution in the matrix acidizing procedure of horizontal wells.
A Holistic Approach to Achieve a Successful Liner Cement in Gas Bearing Early Cretaceous Formations in South Iraq
Authors: Cardenas Miguel Angel , Galaby Amir , Cengiz Ozgur , Al-Rubaye Mustafa , John Melvin , Ponomareva Daria , Antonov Maksim 
Published: January 2020

Obtaining a good cement bond is a continuous challenge, especially if the well being cemented is a high-pressure exploration gas well, and it is one of the very few gas wells drilled in the country. Poor adherence to the casing and the formation, channeling due to gas migration and microannulus are some of the main risks that could result in a poor cement job. Achieving zonal isolation and a good cement sheath protecting the 7-inch liner turned out to be an objective missed for the first two wells of the campaign, compromising the long-term supply of gas to the South region of Iraq. To solve the situation, it was necessary to implement something more than a mere cementing additive; it required a multifactor analysis with an experienced multidisciplinary team. A set of good drilling practices, proper drilling fluids, proven cementing techniques and new technology slurries were combined to improve the precious results.
To obtain a sound cement quality log, the well engineering department teamed up with cementing experts, drilling fluids specialists, liner hanger company representatives and operations personnel. With effective meetings, proper risk assessment and visible leadership, the team generated a series of initiatives that included: drilling hydraulics optimization, mud weight selection, drilling practices re-definition, liner hanger procedure adjustments and cementing slurry design.
As a result, the borehole caliper was significantly improved, the liner hanger allowed full rotation while cementing, cement returns were observed above the liner top after the job, no evidence of gas migration was observed and the CBL-VDL-USIT log showed a remarkable improvement in the two jobs where the engineering initiatives were applied.
Being able to achieve a positive proof on cementing integrity, one of the most important acceptance criteria for the National Oil Company (NOC) regulation entity, enhanced the trust on the technical experts of the engineering team to deliver solutions of complex problems.
Utilization of Pump and Pull Cementing Technique in Highly Deviated and Horizontal Wells
Authors: Alghamdi Muataz , Alwarthan Abdulsalam , Bouaraki Mouloud , Abbas Athman 
Published: January 2020

Pump and pull cementing method is introduced to overcome soft cement plugs due to the swabbing effect and contamination in an oil-based mud environment. The method aims to address quality concerns in challenging well profiles where conventional cementing techniques are deemed to fail, which potentially lead to additional cost for remedial cementing work and non-productive rig time.The method is utilized to tackle a re-occurring issue of tagging soft cement plugs that are used for several applications, including plugging and abandonment and sidetracking operations, in deep highly deviated or horizontal wells. In such profiles, fluids and cement don't balance themselves as gravity is not the predominant factor. Subsequently, the cement plug cannot be balanced, and contamination takes place resulting in its failure. The method targets minimizing this by reducing the effect of pulling out of the plug by keeping the drill pipe stinger inside the cement slurry and replacing the volume created while pulling out of the hole by pumping cement until completing the placement of the plug.The technique is time sensitive since most of the cement slurry remains in drillpipe while preforming the job. For that reason, intensive planning is required to ensure successful implementation. One factor that impact the quality of the job is the abundance of actual downhole data, including caliper and temperature logs. Based on that, cement slurry design can be adjusted to account for temperature effect as well as adjusting volume calculations. Also, lab and computer simulations play a significant role in determining several parameters such as spacer formulation, mud removal efficiency, ultimate compressive strength chart, and additives concentrations, especially retarders. In terms of field preparedness, specific equipment and competencies are required for such critical jobs. The method was deployed successfully in several jobs, resulting in excellent cement quality. At the top of that, the method was used to optimize operations by pumping a single long cement plug instead of several balanced cement plugs. This has directly resulted in saving several rig days while delivering satisfactory cement hardness. A couple of case studies are introduced to showcase the effectiveness of the method in challenging applications.Pump and pull technique proved that it resolves the challenge of placing cement plugs in highly deviated and horizontal wells. It earns more importance as wells are growing in complexity. Recently, the technique was used to successfully place significantly longer cement plugs, achieving an outstanding level of operational efficiency by saving rig days and resulting in cost optimization of cementing operations by reducing the number of required plugs to be pumped.
Lessons Learned from Established Unconventional Resource Plays: Application to Emerging Plays in the Middle East
Authors: Bromhead Alex , Sutcliffe Owen , Cousins Thomas , Weeks David , Davies Roger 
Published: January 2020

The unconventional revolution in North America has firmly established unconventional resource plays as an integral component of global hydrocarbon production. The established North American resource plays are heterogeneous and vary considerably in terms of play type, stratigraphic organization, and the lithology of the target unit. The Middle East has several world-class source rocks that have charged giant and supergiant conventional fields, which implies many opportunities to develop unconventional resource plays. Within this study, the stratigraphic organization of two prolific source rock intervals within the Early Silurian (Qusaiba Member) and Middle-Late Jurassic (Tuwaiq Mountain Formation and equivalents) is characterized from public-domain data sets. From this, a variety of unconventional plays are conceptualized within these resource intervals.The systematic classification of established resource plays in North America facilitates analogue identification for these emerging resource intervals across the Middle East. The Montney play is identified as an analogue for the Silurian resource interval and can be used to help validate unproven unconventional play concepts. Within the Jurassic resource interval, multiple analogues are identified that characterize different aspects of the emerging unconventional play types. For instance, stratigraphic architecture within the emerging Tuwaiq Mountain shale play is comparable to the Vaca Muerta play of the Neuquén Basin in South America, while mineralogy is similar to that within the Eagle Ford play and porosity development is akin to the Marcellus play. Applying understanding from these analogues can enable more informed and efficient exploration, appraisal, and development decisions within these frontier and emerging Middle East resource plays.