bluuebunny/crossref_metadata_2025 huggingface dataset:
New, Integrated Approach to Diagnose, Characterize and Locate Inter-Well Fracture Connectivity in Carbonate Reservoirs From Transient-Test Data
Authors: Al-Obathani Omar H. , Al-Wehaibi Bandar A. , Al-Thawad Faisal M. , Rahman N. M.
Published: October 2018

Characterization of natural fractures in carbonate reservoirs to the resolution of well tests is reliable for major fracture corridors. These fracture corridors, intersecting or non-intersecting the wells, impact the well performance and the ultimate recovery in the field. Good transient-test data is the key to diagnosing fractures and their characteristics. When fractures exist between the wells, it requires some additional efforts in locating these with respect to the wells.

To overcome this challenge we propose a new approach of building 3D, numerical models to diagnose and characterize the inter-well fracture corridors. In addition, these 3D multi-well, numerical models are to determine the location and the extent of fracture corridors by utilizing dynamic pressure-transient data. The innovative idea of bringing multiple wells to the models to consider interference of wells and fracture corridors makes the models robust.

We have been able to identify the inter-well fracture corridors successfully in carbonate reservoirs by performing pressure-transient analyses on wells. By adjusting the inter-well locations of fracture corridors and the extents of these fracture corridors in the multi-well models, we try to achieve the best possible matches with the transient-pressure data. This integrated approach will provide essential input to 3D full- field reservoir models, and will lead to optimizing field management.
Maximizing Asset Value in a Mature Field Using Logging While Drilling Solutions: A Case Study, Onshore Oman
Authors: Al Jahwari Mohammed , Abdulkarim Anar , Aki Ahmet , Al Ajmi Najeeb
Published: October 2018

Enhanced reservoir understanding is critical for the development program of a mature field. This understanding will optimize petrophysical data gathering requirements, wells construction costs, and overall reservoir management strategy to maximize the asset value.

Logging while drilling (LWD) technologies were used in multiple wells to provide an integrated petrophysical and geomechanical interpretation. The bottomhole assembly (BHA) included LWD gamma ray, resistivity, bulk density, thermal neutron, acoustic, high-resolution imaging, and formation pressure sensors. A deterministic multimineral petrophysical model was used for formation volumetrics and fluid analysis.

Geomechanical interpretation used high-resolution microresistivity imaging and acoustic slownesses together with caliper data.

Historical data were also evaluated to determine sweep efficiency and residual fluid saturations.

LWD sensors have proven to provide robust geological, petrophysical, and geomechanical data, as compared to previous traditional wireline data acquisition.

High-resolution images facilitated fracture evaluation and the determination of the reservoir facies, leading to the identification of flow units.

Integrated interpretation has enabled the identification of the completion intervals. Well test results and the production profiles facilitated the reevaluation of the petrophysical cutoffs for the calculation of the oil in place and remaining oil saturations. Reservoir petrophysical attributes were updated in correlation with other data, including the identified pressure depletion intervals honoring history matching.

The interpreted results, based on LWD data, have facilitated the benchmarking of future data- gathering requirements to optimize the overall reservoir management strategies.

This pilot case study prompted a feasibility study to evaluate various well construction and completion design options, including high-angle and horizontal wells, for the future development program.
Development and Application of an Artificial-Neural-Network Based Expert System for Screening and Optimization of Polymer Flooding Projects
Authors: Sun Qian , Ertekin Turgay
Published: October 2018

Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and its success in prolific production increments. This work develops an artificial-neural- network based expert system by utilizing numerically generated training data using a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledge-base that serves for the ANN training. The injection process starts with water injection and switches to polymer injection when the water cut reaches to a threshold value. The chase-water is followed after a prescribed amount of polymer slug is injected. The expert system is generalized in terms of reservoir rock and fluid properties, rheological properties of the polymer solution, and critical engineering parameters to adjust to the complexities exhibited in the polymer injection projects. In developing the inverse model for project screening and design purposes, we have used an engineering design protocol employing inverse and forward-looking expert systems with the goal of exploiting the non-unique nature of the inverse problems. In this work, we employ the expert system as a forecasting and screening tool that is capable to predict time series based response in terms of oil production, water production and injection well sandface pressure data. The validity of the forward-looking expert system is confirmed via extensive blind test applications within a 5.83% error margin. More importantly, we present a project screening protocol that couples the expert system and particle swarm optimization (PSO ) methodology to maximize the net present value (NPV ) of polymer injection projects. In this way, we take the advantages of the fast computational speed of the ANN model to evaluate the finesses of project parameters. In the application of the inverse expert system, we observe that the proposed design protocol is capable to establish a catalogue of polymer injection design parameters that satisfy an expected hydrocarbon recovery performance. The work described in this paper exhibits the robust nature of the proposed expert system in adapting to strong non-linearities encountered in the polymer flooding projects. The coupled utilization of the inverse and forward-looking modules, enables the design engineers to find solutions that are unique to the problem being studied by simultaneously satisfying the imposed constraints effectively. The expert system proposed in this paper is one of the modules of a comprehensive artificial-neural- network based toolbox that includes a large spectrum of EOR processes.
Consequence of Graphene Oxide Nanoparticles on Heavy Oil Recovery
Authors: Elshawaf Mohamed
Published: October 2018

Heavy oil reservoirs embrace 70% of worldwide oil reserves. A lot of challenges face such oil production like its large viscosity which can be reduced under the action of aquathermolysis reaction. Aquathermolysis reaction is the main objective used to analysis and explain the effect of nanoparticles addition on heavy oil. Several thermal recovery techniques have been implemented using different nanometals for recovery improvement of heavy oil reservoirs and viscosity reduction.

These published trials focused on nanometals but none of them addressed usage of Graphene oxide nanoparticles for such improvement of heavy oil recovery, and therefore this paper represents an experimental investigation of graphene oxide effect on heavy oil production. The present work examines graphene oxide nanoparticle in heavy oil viscosity since graphene is a superlative material that has an extraordinary thermal conductivity up to ten times value of any nanometal. In order to check its efficiency for Heavy oil recovery, several published scenarios have been executed on light oil which leads to recovery reaches 12.5 %.

In our work, the concentration used for these nanoparticles is ranging from 0.01: 0.5 wt. %. The viscosity of these nanoparticles with heavy oil sample has been measured to explain the expected improvement in recovery factor. The Experimental work showed a large change in the viscosity after using nano Graphene oxide reached to 40:60% reduction in its original values. In addition to the viscosity, the effect of reservoir temperature is investigated. The range of temperature used in this study varies between 40° to 100° C. These results reflect strong indications for better viscosity reduction. Therefore, better recovery factor for this heavy oil.

Meanwhile, this present research provides an investigation of aquathermolysis reaction for such materials which is the main reason for heavy oil viscosity reduction, also it represents Graphene Oxide as new nanoparticles for improving Heavy Oil Recovery that will create a new era in thermal recovery for heavy oil. Also, an economic study is investigated.
Post Frac Proppant Clean Out While Testing
Authors: Nassef Amr , Al-Basha Hussain , Al-Qahtani Nasser
Published: October 2018

Conventionally, after a well has been fracked using proppant, wells are flowed back to clean using SMS (Sand Management Systems) equipment. Only after proppant levels go to a minimum, the flow is diverted to the testing Equipment and the well gets tested. This paper proposes an alternative approach where operating companies are given the opportunity to continuously monitor the well behavior and its production potential through well testing that takes place simultaneously during the cleanup and proppant disposal. It also proposes a solution to reduce or even eliminate flaring during the clean-up process.

Flowing wells with high solid content has always created the risk of wash outs due to the high erosion it creates. The risk of erosion is way higher during post frack clean up where proppant travels with gas at extreme velocities. Well Testing companies use SMS equipment to control and knock out solid contents in the flow. Usually, the flow is directed to the flare until the well is clean & proppant free to avoid any erosion to the well testing equipment and the production line. The proposed approach includes utilizing five different types of SMS equipment, rigged up in series to secure a proppant free fluid flowing downstream. The system consists of a Sand Catcher, Sand Filter, Sand Snoop, Choke, & a 4 phase separator rigged up respectively in series.

The design was tested in more than one location on high pressure gas wells in Bahrain. It was observed that Sand Catchers remove the bulk of the proppant facilitating quick and time efficient clean up. The filter however picks up the remaining solids that have managed to pass the Sand Catcher. The sand snoop gives the operators a close monitoring facility to guarantee no solids are passing this stage. The Choke controls the velocity on the upstream and reduced pressure on the downstream. The 4 phase separator however, acted as a backup plan and as a mitigation in case any solids reach this stage. Testing the well utilizing the separator was possible during the cleanup and flow easily directed to production lines without any risk of erosion to the testing equipment and to production line.

None of the technology proposed in the paper is new. However, the paper adds value to the existing body of literature by enhancing the utilization of existing technology with an almost flawless design which results in a more cost effective & environmentally friendly solution for post frac clean ups and testing.
Structure-Solubility Correlation for Asphaltene Deposit Removal
Authors: Hamzaoui Bilel , Al Moajil Abdullah M. , Ghamdi Abdulaziz Al
Published: October 2018

Several types of fluids are used to remove the heavy organic deposits precipitated along the wellbore, the gravel pack, the screen, or other equipment for processing the subterranean formation.

The effects of solvent type, temperature and additives on the solubility of the aggregated asphaltene particles were investigated. For the same solvent, the quantitative behavior of the solubility with temperature were similar, displaying an increase in the solubility at higher temperatures. To identify the effectiveness of solvent type and additives to dissolve asphaltenes, various aromatic, aliphatic, heteroatom and surfactant based solvents were used. It was found that heteroatom, surfactants and hydrogen donor compounds increased the solubility by a moderate degree, whereas aromatics increased the solubility by the highest degree. Aromatic solvents such as xylene are not faveroed during asphaltene removal treatments because of low flash point.
Creating Indigenous Technology: Utilization of Local Resources
Authors: Shaikh U. A. , Khayyat I. M.
Published: October 2018

Saudi Arabia is undertaking economic reforms where it is working towards reducing imports, encouraging manufacturing, and promoting the creation of localized technologies. This provides the Kingdom's private-sector with a unique opportunity for growth and expansion, in an effort to maintain relevance and maximize profits. One possible approach to achieve this is the establishment of indigenously grown research and development centers which utilize local talent and resources. Unfortunately, local talent is not necessarily at the level at which the future economy needs it to be and needs to be cultivated and nurtured with the correct methodology.

This paper outlines a strategy for the development of local talent in the course of business operations and defines the various programs and initiatives that can be executed in the private-sector. It details a framework that companies can follow to mature and develop fresh hires for work in both traditional engineering projects and product development.

Moreover, this paper describes the implementation of the aforementioned strategy and methodology by Rawabi Holding Company in an effort to not only develop innovative solutions and increase revenues, but also stimulate economic growth in Saudi Arabia's evolving environment. It analyzes the efforts taken by the company in order to develop their locally sourced talent in their established research and development group and evaluates the success of the measures taken.

In summary, this paper provides a roadmap proven in the local market for talent development which can be used by the private-sector to benefit companies in transitioning to a more development and manufacturing oriented Saudi Arabia.
A Journey Towards Building Real-Time Big Data Analytics Environment for Drilling Operations: Challenges and Lessons Learned
Authors: AlBar Abdullah H , Alotaibi Bader M , Asfoor Hasan M , Nefai Mohammad S
Published: October 2018

Establishing a Big Data Analytics environment for Drilling operations is impacted by many factors such as the nature of drilling operations that requires quick decision making and has a diversity of data sources. This paper goes over the process of building a Real-Time Big Data Analytics environment and highlights key learning and challenges from this endeavor.

The process of building such an environment is multifaceted. It involves building a Big Data solution architecture capable of handling the expected workload which includes servers, network, and software architecture. In addition, it requires establishing a data engineering pipeline that enables combining drilling data sets coming from different sources, reformatting and optimizing it to simplify and speed-up analytics.

The data engineering pipeline is used to tackle different drilling data types which include a master structured database that describes the drilling planning, configurations, and operations, real-time drilling sensor data stored in WITSML semi-structured format (an E&P specific extension of XML), in addition to other unstructured content such as drilling reports.

Data quality procedures were also added to the pipeline in order to identify and handle outliers in the data. In addition, data wrangling procedures were developed to ensure that the data is in the right shape and ready for analytics and machine learning. Moreover, this drilling analytics environment was built while maintaining all business security policies and fine-grained access control rules defined on the original data sources.

The established Big Data Analytics environment results in a simpler and a shorter data science lifecycle and thus making it easy to combine, explore and deploy analytical models. This leads to more efficient business operations. Building a successful analytics environment requires much more than the technology piece. It involves many factors such as data ingestion, cleaning, wrangling while maintaining business security policies. This paper provide a unique perspective on how to build such an environment for real-time drilling operations.
Drilling Influences on Formation Breakdown in Hydraulic Fracturing
Authors: AlBahrani Hussain , Al-Yami Abdullah , Hamid Osman , Wagle Vikrant
Published: October 2018

The influence imposed by drilling operations on the outcome of hydraulic fracturing has been well studied in terms of the post-frac stage productivity. Drilling induced formation damage caused by drilling fluids solids and filtration invasion is routinely linked to both the design and the results of stimulation operations in general. Nonetheless, hydraulic fracturing performed on deep and tight sandstone reservoirs presents a new challenge that requires a new perspective when it comes to analyzing the link between drilling and fracturing. The tightness, depth, and highly stressed nature of these formations mean that achieving formation breakdown for the hydraulic fracture initiation is a challenge. To gain a better understanding of this challenge, the role played by drilling in influencing formation breakdown is examined using different types of drilling data pertaining to stimulated intervals.

The proposed examination is carried out by uncovering the variations in different sets of drilling data and correlating those to the results of fracturing. The sets of drilling data considered describe the drilling fluids rheology, drilling fluids interaction with the formation, and the drilled wellbore quality. These observed variations are then investigated through lab experiments where applicable. Other than lab experiments, the links between drilling influences and formation breakdown is established through either data analytics or technical evidence provided by the published literature. Upon establishing the link between drilling influences and fracturing, detailed recommendations are produced to improve the success rate of hydraulic fracturing operations in terms of formation breakdown.

As anticipated, parameters indicating the damage-ability of the fluids used to drill the stimulated intervals showed a clear link to the outcome of formation breakdown attempts. These parameters are mostly measured by the Particle Plugging Apparatus on location prior to and while drilling the intervals of interest. Recommendations to mitigate the effect of these parameters is issued based on a redesigned formulation of the drilling fluid employed. Other influences include certain drilling events that limited the burst pressure rating of the downhole tubulars (casings and liners) to a value below what is necessary to initiate a fracture.

The work presented in this paper has the potential to significantly improve the success rate of stimulation operations in deep and tight sandstone reservoirs. This is proposed to be achieved by uncovering new links between different drilling influences and the formation breakdown. Complementing the outcome of this work with the rich body of literature investigating the relationship between the post-frac stage productivity and drilling can present a new pathway to access reserves in challenging environments.
Optimizing Impressed Current for Effective and Economic Cathodic Protection of Well Casings
Authors: Sharma Hemant K. , Al-Mulhim Abdulrahman K. , Al-Mutairi Saad M.
Published: October 2018

Anodic corrosion is a direct contributor to external well casing leaks. For some of the exploration and production (E&P) companies, it has been effectively addressed by investing in and installing cathodic protection systems using surface DC rectifier systems that supply Impressed Current Cathodic Protection (ICCP) in wells across all oil and gas fields. Yet, casing leaks due to external corrosion remain a recurrent conundrum, and casing completions still require continual monitoring and repairs despite significant capital investment and energy expenditure.

Recommended design of efficient ICCP systems via modeling is one of the solutions for achieving optimum casing protection. The method for determining whether all anodic zones are eliminated and to ensure that too much energy is not consumed and wasted is to physically measure current flow across the entire casing length, establish flow direction, as well as authenticate the depth of maximum ICCP effectiveness through an effective monitoring program.

This paper describes multiple wells utilizing ICCP, measuring downhole current flow within casings while utilizing existing or historic surface impressed amperage. Once the direct current (DC) profile is acquired across the casings and an effective ICCP depth is established, then surface amperage is either adjusted higher to increase maximum casing protection depth or it is tuned lower to reduce amperage for the purpose of economizing power consumption. Using proper cathodic protection systems not only optimizes the amount of the cathodic current requirement but also enhances the life of the solar modules for solar photovoltaic systems or life of anodes for the ICCP. In addition to ICCP profiling and fine tuning the cathodic current, the corrosion logs for these wells are also compared with detailed analysis.
Completion Evaluation to Stimulate and Test Tight Laminated Sands
Authors: Al-Ameer Musab N. , Uche Ifeanyi , Camacho Diego , Al-Otaibi Nashi M.
Published: October 2018

Tight gas sands worldwide hold significant gas reserves and a vast majority of this low permeability rocks are sandstones. Stimulating tight laminated sands pose a great challenge in terms of completion and stimulation practices. Laminated sands have often been bypassed due to the high cost of hydraulic fracturing and the need to design a fit for purpose completion system. Therefore, it is important to develop an approach to address this and also get better understanding on the impact of stimulation and completion strategy for tight laminated gas sands in Saudi Arabia. High pressure is often required to break down the formation and propagate hydraulic fracturing treatment. This paper describes case histories and solutions for better completion designs in order to stimulate laminated tight gas sands successfully. With the demand to optimize Expected Ultimate Recovery (EUR), tight laminated sands have become an interesting target for unconventional gas resources with some intervals with potential based on logs, but faces challenges stimulating due to completion design. This paper compares the results of wells that were completed in the area, reviewing detailed stimulation and completion design and providing recommendations for future completion.
History Matching a Gas Reservoir Using Ensemble Based Methods
Authors: Ravanelli Fabio , Pamukcu Yusuf
Published: October 2018

Ensemble smoother with multiple data assimilation (ES-MDA) is an advanced assisted history matching technique that is capable of reducing the utilization of existing computational resources while improving the quality of the simulation models by preserving the geological consistency of the model during the history matching process.

The subject reservoir in this paper was modeled using an object based modeling approach with appropriate object size distribution and connectivity. This approach generated a stacked dunes-interdunes complex that models the objects as isolated geobodies as observed in dynamic data.

A set of geological realizations were generated by encompassing to capture the uncertainty in sand geobodies distribution, permeability variation and flow barriers. These geological realizations were history matched using the ES-MDA with covariance localization using the state of art in-house reservoir simulator, GigaPOWERS.

The final model attained an excellent history matching quality and predictability capacity. A comparison between the manual history matching results and the ES-MDA is presented to illustrate the value and the impact of the methodology in reservoir simulation studies. The results obtained strongly encourage the further utilization of the presented methodology for history matching.
Investigation of Heavy Oil Recovery Using Sequential Viscoelastic Surfactant and Chelating Agent Solutions as EOR Fluid for HTHS Conditions Carbonate Reservoirs
Authors: Janjua Aneeq Nasir , Sultan Abdullah S. , Kamal Muhammad Shahzad
Published: October 2018

Viscoelastic surfactants are known to be the best for chemical EOR (cEOR) applications as compared to polymers and surfactants because of its dual capability of reducing the oil/water interfacial tension (IFT) and improving the sweep efficiency. Carbonate reservoirs become most challenging cEOR targets when they are characterized as high temperature and high salinity (HTHS). In this work, a systematic study is carried out to design a formulation using a sequential viscoelastic surfactant (VES) and chelating agent (CA) solutions for recovering heavy oil from carbonate reservoirs.

The objective of this work is to investigate the chemical formulations of viscoelastic surfactant and chelating agent with heavy reservoir oil of 17°API and 234,189 ppm salinity formation brine. Thermogravimetric analysis (TGA), nuclear magnetic resonance (NMR) and fourier transform infrared (FTIR) are used to evaluate the thermal stability of VES. Encouraging results with TGA demonstrate that VES is thermally stable and show high resistance to temperatures up to 250°C. NMR and FTIR results also show good long-term thermal stability when aged for 30 days. Ultra-low oil/water interfacial tension measurements are recorded using spinning drop tensiometer and lie in the range of 10−1 to 10−2 m-Nm−1. Effects of concentration, time and temperature on IFT are evaluated. It is also noted that ultralow IFT is obtained at 50°C and 80°C. Static adsorption has been evaluated by shaking the powdered core samples with VES at two different temperatures for 24 hours. Concentration measurements are performed using total organic carbon (TOC) analysis. Static adsorption results give less adsorption when we have higher temperatures compared to lower temperatures. Coreflooding experiments are designed with VES and VES-CA at 90°C using carbonate core samples to determine the additional oil recovery. Overall oil recovery factor with VES and VES-CA of 47% is calculated when plotted against injected pore volumes. Pressure drop profile, oil rate and water rate are also determined, and their graphs are presented with injected pore volumes.

This study provides an integrated approach of evaluation and application of viscoelastic surfactant and chelating agent solutions for chemical EOR in heavy oil reservoirs. Thermal stability, ultralow IFT's, adsorption and additional oil recovery obtained with viscoelastic surfactant and chelating agent show that they are excellent additives that can be used in cEOR for high salinity and high temperature conditions. They are also very useful when we have heavy crude oil and where IFT reduction is required to mobilize the oil and improve the sweep efficiency of the reservoir.
New Approach to Predict Fracture Pressure Using Functional Networks
Authors: Abdulmalek Ahmed S , Elkatatny Salaheldin , Abdulraheem Abdulazeez , Mahmoud Mohammed , Ali Abdulwahab Z. , Mohamed I. M.
Published: October 2018

Fracture pressure plays a key role in designing the mud weight and the cement slurry density in the drilling operation. Knowing the fracture pressure will eliminate many problems such as loss of circulation and hence reduce the time and the cost of the drilling operation. Many empirical models reported in the literature were used to calculate the fracture pressure based on different parameters. Most of these models used only formation and rock properties to estimate fracture pressure. Other models predicted the fracture pressure based on log data using a few real field data. Artificial intelligence techniques once optimized can be used to predict the fracture pressure with high accuracy.

The objective of this research is to predict the fracture pressure based only on surface drilling parameters which are easy to get namely weight on bit (WOB), rotary speed (RPM), drilling torque (τ), rate of penetration (ROP), mud weight (MW) and formation pressure (Pf). More than 4700 real field data points are used to predict fracture pressure using Functional Networks (FN) which is a method of artificial intelligence (AI).

Functional Networks (FN) tool was compared with different empirical models. The result showed that FN methods outperformed all the fracture pressure equations by high margin (very high correlation coefficient (R) of 0.986 and a very low average absolute percentage error (AAPE) of 0.201). the developed technique will help the drilling engineers to design the cement slurry and determine the casing setting depth. In addition, the drilling engineers will be able to eliminate the common drilling problems such as loss of circulation.
Drilling and Enlarging Surface Pilot Holes in Hard Formations Utilizing Drill Bits, Save Time, Enhance Performance and Reduce HSE Risks
Authors: Atriby Kamal , Scagliarini Stefano , Alfaqhi Abdulqawi , Aljumah Ali , Sindi Albadr , AlGhofaili Saleh
Published: October 2018

In some oilfields, drilling surface big-size wellbores through hard formations yields low drilling performance. Moreover, in these environments, high Shock and Vibration (S&V) are generated causing premature failures of the drilling rig equipment and the drillstrings, increasing rig maintenance costs, Non-Productive Time (NPT), and the risk of loosen drilling rig equipment that could result in dropped (falling) objects and consequent potential injuries to the drilling crews. In these cases, it is envisaged to use the Kelly system for drilling to prevent damage to the Top Drive System (TDS) that however, leads to non-efficient operations and to an increase of Health Safety and Environmental (HSE) hazards in handling more connections (singles).

To improve efficiency, a pilot hole is drilled with a smaller drill bit to the section total depth using a performance downhole motor as the driving mechanism to deliver the required power, torque, and revolutions. The pilot hole is then enlarged to the required bigger-size borehole using a drill bit and, again, a downhole motor. The Bottom Hole Assemblies (BHAs) for both the pilot hole and the enlarged borehole, are designed and optimized to minimize BHAs' components handling, minimize S&V and to improve overall operational efficiency. To date, this technique has been successfully implemented in many wells in different drilling environments, improving the section drilling performance by 40-50%, and reducing both well time and drilling costs. Also, S&V diminished, with a consequent reduction of the HSE risks.

This paper highlights the engineering aspects of the pilot hole and hole-enlarging design and implementation, together with the results obtained.
Challenging Conventional Best Practices with an Updated Productive Drilling Solution
Authors: Al-Majed Alawi , Soh Azrin , Ali Anis , Farid Mazhar , Jallouli Mohamed Amine
Published: October 2018

Among the challenges facing an operator while drilling offshore in the Middle East are the 16-in. sections of wells where highrisk of losses and torque and drag limitations force the operator to be extremely conservative during the planning stage. Operator objectives for this particular interval normally call for mitigating any high-potential incidents, which is driven by the past experiences as well as decades of old best practices. The approach used in the past has been to drill with a positive-displacement mud motor and weighted mud until losses are experienced, and then switch to mudcap drilling to maintain hydrostatic while drilling. The positive displacement mud motor efficiency is excellent in lower inclination wells but deteriorates once the inclination exceeds 30n, leading to significantly lower penetration rates and extending the openhole wellbore exposure time. This prolonged openhole time exposes the bottomhole assembly and wellbore to the same risks the operator has always attempted to avoid.

A service provider evaluated the drilling method with the objective of reducing the drilling time and drilling risks. Drawing from offset well experiences and the conditions of successful operations, a motorized rotary steerable system (RSS) was proposed to the operator. Time and cost analysis were performed, showing that improved hydraulics and drilling dynamics would result in significanttime savings and should be compounded as the 16-in sections are drilled in batches of up to seven wells.

The operator implemented the recommended BHA and parameter design for the remaining seven wells, resulting in up to a 120% increase in the average rate of penetration by the motorized RSS over conventional positive displacement motors. The accompanying benefits to the operator included increased hole cleaning capacity, torque and drag reduction in tripping times, and reduced risk exposure in the 16-in. sections.

The results obtained with the updated design demonstrated that in the current challenging energy market environment, using proven technologies to challenge decades of best practices can bring significant benefits to the well construction and enhance the performance benchmarks for future wells.
Predicting Rate of Penetration Using Artificial Intelligence Techniques
Authors: Al-AbdulJabbar Ahmad , Elkatatny Salaheldin , Mahmoud Mohamed , Abdulraheem Abdulazeez
Published: October 2018

Rate of Penetration referrers to the speed of breaking the rock under the bit. It measures the speed or the progress of the bit when it drills the formation. It has been reported in the industry that high percentage of the well budget is spent on the drilling phase, thus many drilling operators pay close attention to this factor and try to optimize it as much as possible. However, it is very challenging to capture the effect of each individual parameter since most of them are interconnected, and changing one parameter affects the other. As a result, many companies maintain a data for the drilling performance per field and set certain benchmarks to gauge the speed of any newly drilled well. To date, no solid or reliable model exists because of the complexity of the drilling process, and one cannot capture every factor to predict the rate of penetration. Therefore, the utilization of artificial intelligence (AI) in the drilling applications will be a game changer since most of the unknown parameters are accounted for during the modeling or training process.

The objective of this paper is to develop a rate of penetration model using artificial neural network (ANN) with the least possible number of inputs. Actual field data of more than 4,500 data points were used to build the model. The inputs were pumping rate, weight on bit, rotation speed, torque, stand pipe pressure and unconfined compressive strength. Well-A was used to train and test the model with 70/30 data ratio. Then two unseen data which are well-B and well-C were used to test the model. ANN was used in this study, with many sensitivity analyses to achieve the best combination of parameters.

The obtained results showed that ANN can be used effectively to predict the rate of penetration with average correlation coefficient of 0.94 and average absolute percentage error of 8.6%, which shows 22% improvement over the current published methods. The best ANN model was achieved using 1 layer, 12 neurons and a linear transfer function. The developed ANN-ROP model proved to be successful using only six inputs and having a total of two wells with unseen data.
Linking Geochemical and Mechanical Properties of Rock Samples Using New Non-Destructive Techniques
Authors: Hussain Maaruf , Amao AbdulJamiu , Jin Guodong , Al-Ramadan Khalid
Published: October 2018

Geochemical analysis of rocks is fundamental to the understanding of geology and earth sciences. X-ray dispersive spectrometry and other automated techniques are increasingly being used to determined and quantify the abundances of the major, trace elements and other rock properties. This study utilized a combination of dispersive spectrometric techniques (MicroXRF) and impulse rebound hammer method to establish links between geochemical and mechanical properties of rocks through a non-destructive method. MicroXRF has high resolution and can detect trace elements within the parts per billion range. The micro-rebound hammer was used to generate a reduced Young's modulus (E*), which gives a measure of the rock strength with negligible impact on the rock itself.

In order to explore, visualize and understand the dataset generated, principal component analysis (PCA) was applied to emphasize variation and bring out strong patterns in the dataset. The first two dimensions of PCA express 57.09% of the total dataset inertia; that means that 57.09% total variability in the data is explained by the planes/dimensions. The first dimension, which showed a strong positive correlation to clay forming minerals and rock strength, was tentatively identified as the clay gradient. The second dimension describes diagenetic alteration processes responsible for the enrichment of elements such as Ni, Mo etc. Further, a positive correlation was established between E* and four elements Cobalt (Co), Strontium (Sr), Titanium (Ti), and Zircon (Zr). Remarkably, Silicon (Si) had a negative correlation with all elements but positive correlation with porosity and permeability. We therefore identified Co, Ti, Sr, and Zr as proxy for the determination of rock strength specific for studied samples and proposed a workflow based on our sequences of analysis and interpretation. Furthermore, we identified four chemo-mechanical facies through hierarchical clustering of the product of the PCA.

This presented methodology could be specifically useful for geomechanical characterization of rocks; a key requirement needed for in-situ stresses estimation, wellbore stability analysis, reservoir stimulation and compaction, pore pressure prediction, and more importantly for characterizing drill cuttings where size and time are limiting. Drilling operations require constantly evolving cost effective and time efficient techniques, the proposed workflow will serve these purposes i.e. rapid determination of elemental composition (microxrf) coupled with E*will give a reliable proxy for rock strength. The technique can be applied to, drill cuttings, slabs and whole core directly without prior sample preparation.
Removing Dispersed and Dissolved Hydrocarbons From Water Using Adsorption Media Systems With Multiple Regeneration Processes
Authors: Smathers Caleb , Jackson Tommie , Buckwald Scott , Gonzalo Raul , McPherson Ryan
Published: October 2018

Clean water is a precious resource in the world. For decades, nations and companies have focused on delivering contaminant-free clean water as a byproduct of industrial processes. ProSep's Osorb Media Systems (OMS) deliver oil free water from the oil and gas industry's most challenging onshore and offshore water treatment applications. OMS not only remove challenging hydrocarbon contaminants from produced water, they do so with high efficiency over a long media life. Osorb uses a physical adsorption mechanism to remove hydrocarbons from water. Additionally, the unique structure of the media enables the adsorption isotherm to be reversed thus releasing the captured hydrocarbons from the media. The regeneration process is completed using a combination of physical and/or thermal processes that enable hydrocarbon recovery.

Two pilot tests and one field test were completed demonstrating the OMS treatment and regeneration capabilities for both dispersed and dissolved oil removal. Three different regeneration methods were found to be effective. The first pilot test demonstrated over 99% removal of dissolved hydrocarbons throughout 28 water treatment and steam regeneration cycles. A second pilot test demonstrated a 2.6:1 (wt:wt) recovery of crude oil from Osorb while maintaining efficient water treatment. The field test had eight regenerations (five with steam and three with natural gas) completed and the media maintained 98% removal efficiency and averaged <1 mg/L of dispersed oil in the effluent water.

OMS provide a proven technical solution along with the economic feasibility to treat dissolved and dispersed hydrocarbons from water which have proven challenging for the oil and gas industry.
A Novel Polymer Nanocomposite Graphene Based Gel for High Temperature Water Shutoff Applications
Authors: Almoshin Ayman M. , Alsharaeh Edreese , Fathima Arshia , Bataweel Mohammed
Published: October 2018

This study suggests a polymer nanocomposite gel system that can effectively be used as water shutoff material for high temperature reservoirs. Based on nanotechnology, a novel cost effective and ecofriendly polymer gel formulation is presented. This newly developed material extends the temperature limitations for high temperature reservoirs.

In particular, this paper reports an innovative graphene-based zirconium oxide nanocomposite as a crosslinker for water shutoff utilizing polyacrylamide polymer and its derivatives. Thermogravimetric analysis (TGA) and X-ray diffraction (XRD) were utilized to characterize the fabricated gel samples. The microstructure of the polymer nanocomposite gel was analyzed using scanning electron microscopy (SEM). The new developed formulation of the nanocomposite gel fluid was evaluated by rheometer tests at different ranges of pH (temperature up to 330°F) to study the gelation behavior and performance of the system for water shutoff application. Furthermore, the newly developed fluid system was injected into core samples to evaluate the ability of the gel to resist extrusion and determine the strength of the treatment under reservoir conditions. The polymer nanocomposite gel showed surprising mechanical properties with extraordinary thermal properties at elevated temperature. The TGA result revealed a remarkable shift of three main decomposition regimes at high temperatures, which confirms the enhancement of thermal stability of the synthesized nanocomposites polymer gel. The XRD pattern of the polymer gel had peaks that confirm the existence of the graphene and zirconium oxide in the system. The SEM images showed that this new class of polymer gel has a homogeneously distributed 3D network microstructure. The small size of the gel grid pores made the network structure thermally stable and firmly locked water within the gel even under high temperatures. The addition of sodium carbonate could also elongate the gelation time from ~70min. to 104 min at high temprature (330°F). The core flooding results showed a significant drop in water production for the sandstone matrix core that had higher permeability before the treatment.

The developed nanocomposites polymer gel with enhanced mechanical and thermal stability can significantly reduce excess water production within high temperature reservoirs at lower costs than the currently available polymer gels.
Leveraging Supercritical CO2 to Rejuvenate Hydraulically Fractured Wells in Unconventional Reservoirs
Authors: Kurdi Mohammed , Veveakis Manolis , Poulet Thomas
Published: October 2018

It is not uncommon that wells drilled in shale reservoirs experience a large Initial Production (IP), followed by a significant drop in productivity a few months after hydraulic fracturing, leading to a reduced Estimated Ultimate Recovery (EUR), with primary recovery factors rarely exceeding 15%. This drop in productivity constrains the economics of wells, and entails operators to drill and stimulate more wells to retain a production rate target. Recently, refracturing has emerged as a means to increase the productivity of these wells. Numerous well interventions are required to isolate and perforate new zones in addition to the increased costs associated with fracturing fluids and proppant requirements.

This paper investigates the physics of using supercritical CO2 as a secondary recovery method to rejuvenate hydraulically fractured wells in shale reservoirs. Under highly in-situ compressive stresses, diagenesis (fluid release) reactions provoke instabilities within the shale generating high porosity channels parallel to the minimum horizontal compressive stress. These channeling localization instabilities exist in ductile formations and are periodically interspersed in the shale's matrix. Induced hydraulic fractures intersect these channels, invoking pressure drawdown and drives production from these high velocity pillars. These channels close with well depletion, causing a sharp productivity decline. This paper predicts the critical fluid pressure above which pressure should be maintained by CO2 injection to prevent the channels from closing.

A computational model was developed for a shale play in Saudi Arabia as a case study. As the in-situ compressional stresses are high and its geologic setting is applicable, the critical fluid pressure is calculated. This paper aims to further the understanding of using CO2 as a secondary recovery technique and helps pave the road for a more sustainable future by sequestering CO2 into the ground and enhancing the EUR of shale oil and gas reservoirs.
The Weak Alkali ASP Flooding Research in High Water Cut Shallow Reservoir
Authors: Gao Ming , Luo Wenli , Zhang Shanyan , Zhang Qun , Shi Yanyao , Sang Guoqiang , Ji Zemin
Published: October 2018

Strong alkali ASP flooding is now the major choice to develop high permeability reservoirs after water flooding in China. The formation was damaged seriously by the component of alkali. Weak alkali ASP flooding technique has become one of the most important research fields in EOR method due to the prevention of side-effects of alkali.

The Laojunmiao oilfield has been developed 79 years since 1939. The waterflooding's ineffectiveness was caused by complex reservoir structure and longtime water flooding. The waterflooding remaining oil distribution of Laojunmiao reservoir was analyzed by sealed cores, logging interpretation, fluorescence analyses, numerical simulation and other means. The appropriate EOR technology of high water cut shallow reservoir was selected by laboratory experiments, numerical simulation and single well test. In order to avoid formation damage and protect environment, weak alkali ASP flooding was chosen as the candidate EOR method.

The recovery factor of sand body type I and II (high permeability) were higher than type III and IV (low permeability). The main remaining oil type was oil membrane at the particle surface. Membrane remaining oil major distributed at the rock surface between the large grain holes (greater than 10 microns), which was suitable for ultra-low interfacial tension chemical flooding technology. The weak alkali ASP flooding injection parameters were identified by indoor natural core experiments and numerical simulation parameter optimization. Due to the low fracture pressure of shallow reservoir, the pressure rising space of weak alkali ASP was just 1-3MPa. It was necessary to choose the appropriate injection speed, realizing injection pressure control, which avoided dynamic cracks forming. The pressure rose from 4.9 MPa to 7.65 MPa during single well injection test. 6 months later, the water cut of effective wells decreased to 81.3%, the injection system was suitable for Laojunmiao oilfield. The injection process and equipment requirements of weak alkali ASP are simple, which has less effect on the environment.

The weak alkali ASP flooding of this paper is different from the conventional chemical flooding, which will provide the necessary support for future applications. The strong alkali ASP flooding will be replaced by weak alkali ASP flooding in the future.