bluuebunny/crossref_metadata_2025 huggingface dataset:
High Rate of Penetration Correction of LWD Magnetic Resonance Data
Authors: Oifoghe Stanley , Thern Holger , Coman Radu , Okowi Victor
Published: October 2018

One of the major challenges of Logging-While-Drilling (LWD) Magnetic Resonance data acquisition is its limited logging speed. Typically, LWD Magnetic Resonance is logged at speeds of approximately 20m/hr (65ft/hr). Higher logging speeds will substantially reduce the vertical resolution of the data and prevent full polarization of the Hydrogen Protons in the formation, thus, introducing errors in the measurement of total porosity, fluid fractions, and permeability.

The axial motion (rate of penetration) of the magnetic resonance data has multiple effects on the acquired data. The main effects occur to the data during the polarization time, and the amplitude of the echoes during the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence time. The effects on the amplitude are broadly referred to as the flow effects.

During the drilling of a well in the Niger Delta, an operator needed to save rig cost by increasing the Rate of Penetration (ROP) for LWD Magnetic Resonance from 20m/hr to 40m/hr. This increased ROP caused an overestimation of the total porosity from magnetic resonance.

A newly introduced correction technique enables the compensation of effects due to high ROP on magnetic resonance data. This ROP correction methodology compensates flow and polarization effects. Total porosity and fluid fractions were corrected, resulting also in an updated Magnetic Resonance permeability index. Validation of the technique was accomplished by an accurate match of the corrected total porosity to results from offset wells.

This paper demonstrates the effect of a high rate of penetration on acquired LWD data. Details of flow and polarization effects, and the procedure for correcting these effects, making the data useable and accurate, are also presented.
Date Palm Tree-Based Fibrous LCM ARC Eco-Fiber -A Better Alternative to Equivalent Imported Products
Authors: Amanullah Md. , Arfaj Mohammed K.
Published: October 2018

A novel fibrous LCM coined "ARC Eco-Fiber" has been developed using deceased date tree wastes to use as an alternative to equivalent imported products. Every year about 5 to 10% trees are discarded due to old age, poor food bearing capacity and also due to the damage and degradation of trees by diseases. Currently, there is no industrial use of the discarded and deceased date palm trees available in the Kingdom. Moreover, the disposal of the deceased and old trees is a big headache for the date farming communities due to the economic cost and their negative impact on surrounding environment and the existing date farm plants. As there is a sustainable source of discarded and deceased date trees in the Kingdom, it is a potential source of raw material for localization of fibrous LCM product development to replace the equivalent imported products. The industrial use of deceased and old date trees will also boost the growth of local industries and enterprises along with the creation of new job opportunities for the local communities. It will also help to uplift the social and economic condition of the date farming communities. The date palm trunk-based fibrous LCM described in this paper indicates good ductile and malleable characteristics and thus expected to have good tensile and compressive load bearing capacity to prevent damage and degradation while pumping.

The performance of the newly developed fibrous LCM "ARC Eco-Fiber" was evaluated using a see-through and a Permeability Plugging Test (PPT) Apparatus. The PPT apparatus used 2mm slotted disc, 250 oF temperature and 1000 psi pressure to conduct the tests. A commercial fibrous LCM product widely used by industry has also been tested to compare the performance of the date palm trunk-based fibrous LCM -ARC Eco-Fiber. The results demonstrated superior sealing and plugging efficiency for the ARC Eco-Fiber with little or no loss of whole mud compared to the widely used commercial fibrous LCM product. Both the conventional and see-through test results indicate effective sealing and plugging performance for the date palm waste-based fibrous LCMs and thus demonstrated the reliability of the product as an alternative to equivalent imported LCM products.
Novel Methods and Test Apparatus for Comprehensive Characterization of Oil and Gas Field Fluids and Additives
Authors: Amanullah Md. , Arfaj Mohammed K.
Published: October 2018

Currently available API test apparatus and methods though provide good guidelines in drilling and drill-in fluid design, they often unable to provide comprehensive fluid and additive characteristics for various application scenarios. This is due to the inability of the current API methods and apparatus to provide application specific information for trouble free drilling and production of oil and gas resources. Moreover, no other industry methods and apparatus are suitable for specific characterization of fluids or additives used for oil and gas field applications. Hence, the industry needs novel test apparatus and methods for comprehensive and better characterization of oil and gas field fluids and additives for trouble free drilling and production operation. This paper describes several novel methods and test set up for comprehensive characterization of oil and gas field fluids and additives for various application scenarios.

Experimental results indicate that the newly developed methods and apparatus provide valuable information on mudcake cleaning and cleaning fluid efficiency, spotting fluid performance, quality control and quality assurance of various sized bridging materials for non-damaging drill-in fluid design, inhibition durability of shale inhibitors to prevent time dependent borehole instability and resilient characteristics of LCM products to improve sealing and plugging efficiency of seals and plugs formed by LCM pills or slurries. The methods introduce several application specific index parameters to provide useful technical guidelines for superior fluid design and appropriate additive selection for trouble free and economic drilling and production operation. The methods will play an important role to discourage the use of trial and error methods in some oil and gas field applications and thus expected to improve the success rate significantly.
Characterization of Emulsion Formation with Nanoparticles for Enhanced Oil Recovery
Authors: Arshad Muhammad Waseem , Feilberg Karen Louise , Shapiro Alexander , Thomsen Kaj
Published: October 2018

Characterization of emulsion formation (amount and droplet size) in the brine–oil–nanoparticle systems as a function of varying size of nanoparticles and modified brine salinity is presented. Different brines were used with a range from zero salinity for deionized water (DIW) to synthetic seawater (SSW), mimicking the salinity of North Sea water. Brines (FW1 and FW2) representing the composition of formation water obtained from different production wells (North Sea) were also used. Two model oils (decane (D) and hexane–hexadecane (HH) mixture of 1:1 vol. ratio) and a sample of North Sea crude oil (NSCO) were used. CaCO3 nanoparticles of three different sizes of 15-40, 50, and 90 nm were used. Nanoparticles characterization was performed with Transmission Electron Microscopy (TEM). A commercially available sonication equipment, Branson Sonifier® SFX250, was employed for emulsion formation in brine–oil–nanoparticles systems. All the experiments were performed at room temperature for the same experimental conditions of 5 minutes of ultrasonic processing by using a 6.5 mm tapered microtip (sonication probe) with an output power of 30 W. Emulsion characterization (emulsion droplet size) was performed with an optical microscope (Axio Scope.A1).

The effect of size of CaCO3 nanoparticles and brine salinity on emulsion formation was investigated for different brine–oil systems. The results showed that the emulsion formation in brine–model oil (D and HH) systems was an inverse function of the size of nanoparticles i.e., a large amount of emulsion formation was observed for the smaller sized nanoparticles and vice versa. Emulsion characterization for these systems showed that the emulsion droplet size increased with an increase in size of the nanoparticles. The brine salinity also showed a significant effect on emulsion formation in brine–model oil systems i.e., a decrease in brine salinity showed an increase in emulsion formation and correspondingly smaller emulsion droplet sizes. However, the brine salinity did not affect the emulsion formation and emulsion droplet size for 15-40 nm nanoparticles. Contrary to the brine–model oil results, the results of brine–NSCO systems neither showed any dependence on the size of nanoparticles nor on the brine salinity. This might be due to the presence of polar fractions (polar acids and polar bases) in the crude oil.

The characterization study presented in this paper can provide a foundation for future development of calcite nanoparticle based EOR applications in the carbonate reservoirs.
Chemically Tuned Waterflooding in Carbonate Reservoirs: Experimental and Simulation Investigation
Authors: Alhuraishawy Ali K. , Han Pu , Almohsin Ayman , Bai Baojun , Wei Mingzhen
Published: October 2018

Low salinity waterflooding (LSWF) has been widely investigated to reduce the residual oil saturation in swept areas and thus improve oil recovery. Recently, extensive studies on crude oil, brine, and rock system reported that LSWF and increased sulfate ion concentration in the injected water could change rock wettability during waterflooding. The objective of this paper is to provide a deeper understanding the effect of sulfate ion concentration and low salinity waterflooding on oil recovery improvement due to wettability modification by applying experimental and simulation approaches.

An experimental model with the properties of the same core was designed to understand the effect of LSWF and sulfate ion concentration on improved oil recovery during the waterflooding process. Reactive transport simulator (CrunchFlow 2007) was used to simulate the experimental result. Once the experimental and simulation results were matched, a sensitivity analysis was done by changing sulfate ion concentration and calculate the wettability index based on chromatographic separation of tracer (SCN-) and sulfate ion (SO42-) to investigate how could affect the sulfate ion concentration on modifying rock wettability. So when the area between SCN- and SO42- increased, the wettability modified toward water wet.

The experimental results found that both LSWF and increased sulfate ion concentration three times can improve oil recovery factor by 10% and 19.5%, respectively. The reactive transport simulator results showed that the area between SCN- and SO42- increased as SO42- concentration increased and improved the core wettability toward more water wetness. The temperature has a significant effect on the SO42- adsorption and the high temperature resulted in more SO42- adsorption and the core wettability modified to be more water wetness.

Combined two approaches, experimental and simulation, could be a viable technique to understand LSWF and sulfate ion concentration effect on improved rock wettability toward water-wet.
A General Compositional Rescaled-Exponential Model for Multiphase Boundary-Dominated Performance Analysis
Authors: Will Ryan , Ayala Luis F.
Published: October 2018

Hydrocarbon reservoir performance forecasting is an integral component of the resource development chain and is typically accomplished via reservoir modeling using either numerical or analytical methods. Although complex numerical models provide rigorous means of capturing and predicting reservoir behavior, reservoir engineers also rely on simpler analytical models to analyze well performance and estimate reserves when uncertainties exist. Arps, for example, empirically demonstrated that certain reservoirs may decline according to simple, exponential, hyperbolic, or harmonic relationships; such behavior, however, does not extend to more complex scenarios, such as multi-phase reservoir depletion. Due to this limitation, an important research area for many years has been to transform the equations governing flow through porous media in such a way as to express complex reservoir performance in terms of closed analytical forms. In this work, it is demonstrated that rigorous compositional analysis may be coupled with analytical well performance estimations for reservoirs with complex fluid systems, and that the molar decline of individual hydrocarbon fluid fractions can be expressed in terms of rescaled-exponential equations for well performance analysis. This work demonstrates that, by the introduction of a new partial pseudo-pressure variables, it is possible to predict the decline behavior of individual fluid constituents of a variety of gas condensate reservoir systems characterized by widely varying richness and complex multi-phase flow scenarios. A new four-region flow model is proposed and validated to implement gas-condensate deliverability calculations at late times during variable bottomhole pressure production. Five case studies are presented to support each of the model capabilities stated above and validate the use of liquid-analog rescaled-exponentials for the prediction of production decline behavior for each of the hydrocarbon species.
An Automated Flowing Bottom-Hole Pressure Prediction for a Vertical Well Having Multiphase Flow Using Computational Intelligence Techniques
Authors: Tariq Zeeshan
Published: October 2018

The need for accurate estimation of flowing bottom-hole pressure (FBHP) is owning an immense importance in petroleum engineering applications such as continuous field production optimization, cost per barrel of oil reduction, assess reservoir performance and to quantify workover remedial operations.

Induction of pressure down-hole gauges in oil wells to measure FBHP is a common practice especially in wells artificially lifted with downhole electrical submersible pumps. However, intervening a producing well is a quite exhaustive and expensive task which is involved with production risk, and disruptions. For these reasons, various empirical correlations and mechanistic models were developed to estimate FBHP. Majority of these models were formed under laboratory scale conditions and are, therefore, imprecise when scaled-up to field conditions. Because of the complexity associated with the numerical modeling and physical implementation these models are also computationally very expensive to run.

In this study, an empirical model based on computational intelligence (CI) technique is developed to quantify FBHP in a vertical well with multiphase flow. The proposed model is based on only surface production data which includes; oil flow rate, gas flow rate, water flow rate, oil API gravity, perforation depth, surface temperature, bottom-hole temperature, and tubing diameter. The data used to develop empirical model covered a wide range of values and are collected from published sources and several wells from different locations. The proposed model is then tested against new field data and results were compared statistically with the estimations of some commonly used empirical correlations and mechanistic models in oil industry. The comparison results show that the proposed empirical model significantly outperforms all other existing models and delivers the predictions with high accuracy. A small average absolute percentage error of less than 2% was found with new proposed empirical correlation, while comparing the existing published correlations on the same data gives more than 15% error.

The novelty of proposed empirical model is that it is very simple and only require surface production data while previous models requires exhaustive computationally expensive calculations. The new model is accurate enough and can serve as a handy tool for the production engineers to forecast the FBHP in wells with high level of certainty.
Carbon Nanotube under High Pressure
Authors: Al-Awami Ali H.
Published: October 2018

Nanotechnology is considered as the next major industrial revolution. It deals with materials at a molecular and atomic scale and is predicted that it will affect all aspects of our lives. Nano-materials are a major branch of nanotechnology that is characterized by different behaviors. One of the promising nano-materials that are expected to play an important role in industry is the carbon nanotubes (CNTs). The CNTs improve the efficiency of many tools, e.g., energy storage, electrical cables, and ultra-capacitors.

CNTs exhibit very different features under extreme conditions, such as high pressure. In addition, doping carbon nanotubes with nitrogen might enhance their performance and allows them for more advanced applications. In this study, we examined nitrogen-doped CNTs (CNX-NTS) under high pressure. We used 1.5% and 5.4% CNX-NTS samples that were exposed to pressure range up to 15 GPa. For both samples, there was no phase transformation. The two sample’s results suggest that doping of nitrogen strengthens the mechanical property of CNTs.

As the results showed, that CNX-NTS can overcome high-pressure rates (more than 15 GPa), and they can be used in applications that encompass high pressure. For example, in oil and gas industry, CNTs can be used in protecting oil and gas operation equipment and structures to provide protection, increase the service life, and decrease the maintenance cost.
Wettability Alteration of Oil-Wet Calcite: A Mechanistic Study
Authors: Gmira A. , Hammami M. A. , Al Enezi S. M. , Yousef A. A.
Published: October 2018

Enhancing oil recovery in naturally fractured reservoirs by injecting chemistry-optimized water has been widely investigated recently and has demonstrated its efficiency at both laboratory and field trials. There is an extensive ongoing efforts in the industry to characterize and understand the responsible mechanisms at scales ranging from nano-scale to field scale. The ionic formulation of the injected brine affects dramatically the crude oil/brine/rock interfaces, altering rock wettability and improving oil recovery efficiency. In this experimental work, a mechanistic study is performed utilizing analytical methods to study the effect of the ionic composition and ionic strength on the rock sample wettability. The combination of Thermogravimetric Analysis (TGA) and Fourier Transform Infrared (FTIR) spectroscopy is a time saving experimental approach, suitable for wettability alteration quantification of rock samples. The results indicate that stearic acid stretching vibrational bands decrease with the decrease of brine ionic strength indicating a partial release of adsorbed organic material from calcite surface. Single ion brines impacted the calcite wettability and sulfate ions were found to be the most effective in stearic acid release followed by sodium, calcium and magnesium. Thermogravimetric analysis confirmed the observed trend and the calcite weight loss due to stearic acid decomposition decreased with decreasing brine ionic strength and confirmed the fact that sulfates ions are the most effective in partial release of adsorbed stearic acid from calcite surface.
Utilization of Advanced, 3D Numerical Models Built With Interference-Test Data for Understanding Regional Hydraulic Connectivity in a Carbonate Reservoir
Authors: Amin Rana S. , Wehaibi Bandar A. , Alghazal Mohammed A. , Rahman N. M.
Published: October 2018

Due process has been followed in launching this focused study, starting with integration and analysis of available static and dynamic data to characterize selected sectors of the subject reservoir. The objective of this initiative is to build 3D numerical models for characterization of the hydraulic connectivity within the sector models. These sectors have been originally taken out of the corresponding static geological models. Some of the wells in the sectors have data from prior transient tests, which have been utilized to condition the permeability around the corresponding wells. But this step has not been found enough to describe the dynamic behavior on a long term. Hence, data from a multi-well, interference test has been utilized to enhance the dynamic characteristics of fluid movement in the numerical models.

This paper presents an integrated approach to characterize the hydraulic communication and heterogeneity in the reservoir. The results of this study have helped improve reservoir characterization in the corresponding part of the reservoir simulation model, providing a more refined input of dynamic pressure and permeability data within the area of interest. Best of all, the reservoir engineers have acquired a wealth of knowledge of reservoir connectivity to be utilized for their reservoir management practices.
Rock Grain Size Prediction from NMR Measurement and Digital Rock Modeling- Experimental Validation
Authors: Ma Shouxiang , Jin Guodong , Sy Rex , Kesserwan Hasan
Published: October 2018

This paper presents an experimental study to test and validate a technique of predicting rock grain size distribution (GSD) from nuclear magnetic resonance (NMR) measurements and digital rock modeling. GSD is one of the basic parameters in geo-science and petroleum engineering. Such information is commonly obtained from sieve or laser particle size analysis in the laboratory on a limited number of core samples. The measured GSD is then approximated to be representative of the targeted reservoir rock. A technique that estimates a continuous GSD profile along a wellbore embodies a significant technical and economic advantage.

In this paper, GSD was predicted from NMR responses of fully water saturated rock samples using digital rock modeling techniques, which generates a rock model and simulates NMR responses by considering mineralogy, surface relaxivity and the surface roughness of rock grains. For validation, NMR measurement, GSD, mineralogy, and permeability measurements were performed on the rock samples used for digital rock modeling. Three outcrop Berea sandstone samples were used in this study; one for calibration to tune the modeling parameters and the other two for validation. The sieve analysis method was used to measure the GSD, in which petrographic observation was applied to confirm that grains were properly disaggregated.

Results from this study indicated that sample composition played a key role in the prediction of GSD from NMR measurements, because grain surfaces change with mineralogy and are affected by diagenetic processes. A parameter, surface roughness factor, was used to account for these effects. For Berea sandstone samples, if its composition is assumed to be pure quartz, the predicted GSD could not match with the measured one. Once the measured mineralogy was used in the modeling, it agreed well with the measured GSD. The same parameters were further used to predict GSD for all remaining Berea sandstone samples, with satisfactory results.

The presented methodology may be applied downhole to predict a continuous GSD profile of a reservoir interval, providing that mineralogical composition and an NMR log are available. Drill cuttings or prior knowledge based on cores can also provide such information. The predicted GSD provides useful information for geo-science and petroleum engineering applications such as permeability prediction.
Emulsifier Developed from Waste Vegetable Oil for Application in Invert-Emulsion Oil based Mud
Authors: Ramasamy Jothibasu , Amanullah Md , Alsaihati Mujtaba M
Published: October 2018

Emulsifiers are a class of chemicals derived from fatty acids or their derivatives and used in water-in-oil based mud (OBM) in other words invert emulsion oil based mud. The role of an emulsifier in invert emulsion OBM is to lower the interfacial tension between water and oil to allow the formation of stable emulsion which is an essential quality of oil based mud. These emulsifiers surround the water droplets like an encapsulation with the fatty acid components extend into the oil phase and acts like a small osmatic cell allowing only water to pass through but not salts. Most of the commercially available emulsifiers are derived from Tall oil fatty acid (TOFA) which shows excellent emulsion stability even at harsh conditions. Our objective in this study is to make use of the huge quantity of used cooking/vegetable oil available in the kingdom and convert to an emulsifier suitable for the application in invert-emulsion OBM as vegetable oil contains a wide range of different fatty acids in the form triglycerides. A comparative study has been carried out by formulating invert-emulsion OBM using commercially available emulsifier and the emulsifier derived from used cooking/vegetable oil. Emulsifier (Arc-Eco-Mul) from used or waste vegetable oil has been synthesized by an in-house developed process. A series of different invert-emulsion OBM have been formulated with varying density using in-house developed product Arc-Eco-Mul as primary emulsifier. For comparison, a mud is formulated using commercial primary emulsifier. Mud properties such as density, rheology, API and HPHT filtration control tests have been conducted for fresh mud and for muds hot-rolled at 300degF and 500psi for 16h. It is observed from the laboratory experiments that the mud samples formulated using 12-ppb of Arc-Eco-Mul have similar rheological properties and better filtration control properties compared to the mud samples formulated using 12-ppb of commercial emulsifier. Most importantly, there is no phase separation in the filtrate collected from HPHT filtration control experiment, which showed a very stable emulsion formed by in-house developed Arc-Eco-Mul. Concentration screening experiments showed that only 6-ppb loading of Arc-Eco-Mul is required to achieve a mud with very good rheological and filtration control properties with high emulsion stability. The in-house developed Arc-Eco-Mul from used cooking/vegetable oil has similar properties as commercial additives that are currently used in the industry. This will open an avenue for recycling used cooking oil for oil and gas industry applications.
Corrosion and Scaling Monitoring under Real Downhole Conditions in Sour Gas Wells
Authors: Chen Tao , Chang Frank , Liang Feng , Mukhles Amro
Published: October 2018

One of the major challenges of corrosion and scaling management in sour gas wells is to effectively monitor corrosion and scaling under real-flow regime conditions. It is very difficult to simulate the actual environment and flow conditions in laboratory experiments to study downhole corrosion and scale formation. Understanding the corrosion and scaling mechanism under downhole conditions is very important in order to develop effective prevention and mitigation strategies in a timely manner.

An advanced downhole corrosion and scale monitoring (DCSM) tool has been designed and developed to monitor corrosion and scale formation in sour gas wells. This monitoring system represents significant improvements over the current industrial technology by directly measuring corrosion and scale deposition in real downhole conditions using exchangeable coupons with identical metallurgy as the downhole completion tubing. A slick line with a retrievable high-expansion gauge hanger was used to deploy and anchor the DCSM downhole at the desired depth. The tool was retrieved after 3 months exposure to the reservoir conditions for post-laboratory analysis. Advanced analytical techniques were carried out to understand the corrosion and scaling mechanism, including SEM, EDS, XRD, and surface profile measurement besides quantifying the weight changes.

The results showed that a thin layer (~3-4 μm in thickness) of iron sulfide scale was deposited on the surface of coupon. It served as a protective layer to prevent and reduce further corrosion and scale buildup. To understand the mechanisms of scaling, the surface scale deposit was removed by corrosion inhibited acidic solution. The surface profile measurement showed localized pitting corrosion which appeared on the surface of coupon, which indicates that corrosion happened first followed by scale layer deposition on metal coupon surface.

The newly developed DCSM tool has an advanced design which allows direct corrosion and scaling monitoring under downhole conditions. Post-laboratory analysis on retrieved coupons can provide corrosion and scaling mechanism for specific metallurgy under real downhole conditions. Proper corrosion and scale management programs could be designed to minimize the effects of corrosive gases. The developed tool can be used to monitor the effectiveness of the corrosion treatment and can be deployed in sweet gas wells, oil wells and water supplier wells.
High Density Drilling Fluids for Managed Pressure Drilling
Authors: Wagle Vikrant , Al-Yami Abdullah S. , Aljubran Mohammad , Al-Bahrani Hussain
Published: October 2018

Drilling with high density water-based muds invariably increases the chances of a stuck pipe. Stuck pipe significantly increases the cost of drilling and decreases the chances of successfully drilling a well within the stipulated time. Drilling fluids formulated with a combination of manganese tetroxide and barite as weighting agents are expected to have the following advantages: a) Better sag resistance b) Lower equivalent circulating density (ECD) c) Lower fluid cost d) Stuck pipe mitigation due to acid solubility of manganese tetroxide. This paper describes the formulation of 100pcf, 120pcf and 150pcf drilling fluids formulated with a combination of barite and Mn3O4 as weighting materials and hot rolled at 270°F/250°F/300°F respectively. The experimental work involves measuring rheological properties, HTHP filtration and static sagging resistance of the fluid at the specified temperature. The paper also describes the data obtained from the field trial of 160pcf fluids formulated with barite and Mn3O4 for wells with a BHST of 300°F. Details are shed on the high-pressure, high-temperature (HPHT) operations across naturally fractured formations with 0.5 - 1.0 pcf mud window.

The paper discusses the advantage of using such drilling fluids in mitigating stuck pipe issues and showcases their benefits in terms of better barite sag resistance and lower equivalent circulating density as compared to conventional drilling fluids formulated with barite as weighting agent. The 100pcf, 120pcf and 150pcf fluids showed superior rheology, thin filter-cake and better sag resistance as compared to fluids formulated with only barite as the weighting agent. The drilling fluids formulated with a combination of barite and manganese tetroxide showed good rheology, barite-sag resistance and resulted in successful drilling of wells having a BHST of 300°F. 160pcf fluid formulated with a combination of barite and manganese tetroxide when field trialed showed good rheology, better sag-resistance thereby resulting in successful drilling of the well. In fact, managed pressure drilling (MPD) operations became more practical with such high mud weights as this novel formulation facilitates mud management and treatment when compared to the conventional recipes. MPD control algorithms are absolutely dependent on the mud system consistency and durability which is a feature provided by this innovative fluid formulation.
New Epoxy Chemistry to Generate Highly Conductive Channels Within the Fracture Geometry Pillar Fracture
Authors: Baqader Nour O. , Kalgaonkar Rajendra A. , Gomaa Ahmed M. , Al Moajil Abdullah M.
Published: October 2018

A conventional proppant pack may lose up to 99% of its conductivity due to gel damage, fines migration, multiphase flow, and non-Darcy flow. Therefore, the concept of pillar fracturing was developed to generate highly conductive paths for hydrocarbon to flow. The success of the pillar fracturing treatment depends on delivering the proppant as pillar stages with a good suspension. This suspension keeps the proppant within the stage, prevents the proppant from diffusing out of the stage, and improves the mechanical strength of the pillar during closure. Resin based chemistries were proposed in the literature for proppant pack consolidation. However, most of these resins are incompatible with the aqueous fracturing fluids. This warrants for special precautions to be undertaken during pumping of the treatment to avoid formation damage.

This paper discusses a new chemistry that has been developed to substitute the porous proppant pack in the fracture with an isolated structure of propped pillars containing a network of open channels. Also, this paper further discusses the experimental procedures to test compatibility of the newly developed chemistry with crosslinked fracturing fluids, optimization to use the minimum concentrations, and making hard plugs of proppants pillars under pressure and temperature (up to 350°F). Furthermore, proppant suspension tests with and without pulsing were conducted at temperatures up to 300°F to evaluate the ability of creating the conductive channels. Finally, the mechanical strength of the created pillars was evaluated using triaxle load frames to confirm that the created pillar will resist the closure stress and keep the fracture open.

Experimental results showed that embedded fluid after gelation can transport the proppant during the injection and closure time without settling, thus avoiding any issues with proppant screen outs. The compatibility test showed that different concentrations of the embedded gel fluid (from 20-50 vol %) was compatible with crosslinked fracturing fluid and fracturing fluid additives. Moreover, this new chemistry was able to suspend the proppants. Additionally, the consolidated proppant pack showed excellent mechanical strength enhancement with the developed fluid system where the proppant pillar can hold the fracture open at high closure stress. Also, it was interesting to notice that oxidizer breakers enhanced the mechanical strength of the developed proppant pillar. The created pillar was conductive and hydrocarbon flowed through it.

The data obtained from this study showcases the development of a new fluid chemistry that can replace conventionally used techniques to transport proppant inside the fracture.
A Novel approach for Mitigation of Shocks & Vibration and achieving drilling performance in carbonate reservoirs
Authors: Balka Muhammad Sarfraz , Ghazzawi Ayman , Melgares Hernan
Published: October 2018

Deep gas drilling in carbonate environment is very challenging due to elevated temperatures with pressures. Additionally, the presence of the shock and vibrations across the interbedded layers of limestone and dolomites. Over the years different drilling techniques are employed for improving the drilling performance. The analysis of the data showed that the wells where the shock and vibrations were lower the optimum performance was achieved and the section was drilled in one run compared to the wells where multiple runs were required because of shock and vibration. Further analysis showed that the Shocks are not only seen while drilling, but the level of shocks was high during non-drilling activity such as reaming during wiper trips, back reaming across tight spots and before reaming while connection. This paper will cover the techniques that were employed to minimize the S&V or at least reduce to the minimum acceptable level where the drilling performance can be achieved.

Understanding the shock and vibration across different formations and sub layers within formation. Comparison of shock and vibration for different BHA's while drilling. Application of the stat of the art drilling dynamic simulator. Comparison of BHA's with standalone and motor power Rotary steerable system. Identifying and developing the strategy while crossing the interbedded layers. Feedback to the reliability team for improvement.

Based on understanding the shock and Vibration, and lesson learned multiple wells are drilled where the number of BHA's used to drill the section are reduced and the ratio of drilling the section in one runs is increasing.
High-Performance Water-Based System Proved an Environmentally-Friendly Alternative for Time-Sensitive Shales in Saudi Arabia
Authors: Hegazy Mohamed , Sharma Sunil , Fares Khaled , ElBatran Ahmed
Published: October 2018

The Khafji and Ahmadi shales in Saudi Arabia are highly dispersive, tectonically stressed formations and tend to result in wellbore instability after prolonged exposure to conventional water-based drilling fluid systems. These time-sensitive formations can cause sloughing shale, packing off, extreme over pull, back reaming, stuck pipe, and in some instances bit and stabilizer accretion, resulting in non-productive time (NPT) to operators. Some off-set wells experienced lost time of up to 30 days, and after failing to continue with conventional water-based drilling fluid, the operator had to plug back and use oil-based drilling fluid to finish the wells.

Historically, a standard KCl/polymer/asphalt system was used to drill these shale sections, but due to related NPT and an extensive evaluation program planned for a candidate well, the need for a more robust fluid was identified. Oil- or synthetic-based drilling fluids were not desired due to logistical and environmental concerns. In this challenging well, the operator planned to cut five cores across a series of formations to complete the geological studies previously hindered due to shale-related wellbore problems. These demanding objectives and the notorious history of the field, required a novel solution that could control the formations while maintaining an excellent environmental and logistical footprint.

This paper presents details of the successful application of a new high-performance water-based drilling fluid (HPWDF) system using a unique triple inhibition approach to stabilize troublesome zones. In this new system, a proprietary polyamine-based shale hydration suppressant, a unique low-molecular-weight encapsulator, and a co-polymeric nano-sized pore-sealant additive worked in synergy to achieve oil-based fluid performance. In the field application, the system exceeded the operator's expectations, with no fluid-related downtime and successful execution of five coring runs. After coring and logging, casing was run and cemented smoothly, even after 42 days of wellbore exposure. With similar formations drilled across the Middle East, this solution has the potential to be used as an environmentally-friendly alternative to oil-based fluids in the Middle East.
Automated Identification of Optimal Deviated and Horizontal Well Targets
Authors: Castiñeira David , Toronyi Robert , Saleri Nansen
Published: October 2018

Horizontal or deviated wells provide a great way to maximize contact with the reservoir target of interest, reduce water and coning issues, allow for a larger drainage pattern, and as a result increase overall recovery. Placement of these wells has historically relied on history-matched simulation models, which require a multi-disciplinary team of people working over an extensive period of time. Moreover, in situations where static and dynamic reservoir models are unavailable, or are out of date, this approach can lead to inconclusive results in addition to being both cost and time prohibitive. In the present work, a new technology is developed to automate and streamline the process of optimal horizontal or deviated target identification in any type of reservoir and depositional environment. This technology relies on automated geologic and engineering workflows to map remaining oil and identify areas with high probability of success, advanced computational algorithms to perform an optimized global search with 3D pay tracking, statistical and machine learning techniques to assess neighborhood performance and geologic risk, and physics-based analytical and parametric models to forecast production. The algorithm can be fed multiple types of constrains including configuration constrains like length range, azimuth range, and deviation range as well as path constrains like zone-crossing, baffle-crossing, and fault surface crossing. An optimization engine allows the identification of targets that maximize a probability of success attribute, designed to reflect trends in key attributes known to influence production performance such as hydrocarbon pore volume, permeability, fracture intensity, baffle layers, spacing constrains, drainage maps, trends in WCT and GOR, fluid contacts, and so on. The identified targets are then further optimized using an interference analysis that selects the best set of non-interfering targets to maximize production. This framework has been successfully applied to several giant mature assets in the Middle East, North America and South America (with massive datasets and complexity), and in situations where static and dynamic reservoir models are unavailable, partially available, or are very out of date. In all these studies, hundreds of deviated or horizontal opportunities are initially identified. We then discuss key elements to consider during vetting to make sure the final set of identified opportunities are geologically sound, meet various validation criteria, and are feasible given the operational constrains.
Application of Jet Pumping Technology for Offloading a Killed Well in a Gas Condensate Field – A Case Study
Authors: Kalwar Shuaib Ahmed , Awan Abdul Quddos , Ahmad Hafiz Junaid , Khan Zubair
Published: October 2018

This paper describes a trial jet pump application for offloading a killed well. The Well-2A was naturally producing an average 1650 BCPD and 1.54 MMSCFD from two separate formations via dual strings of size 2-3/in. in a 7 in. casing. It later required a workover job because of tubing string and packer leakage. The well was recompleted with a single string of 3-1/2 in. tubing in order to produce both formations together. The well was killed and initially kicked-off by injecting nitrogen, but it was unable to flow even after continuous pumping of 4,000 gallons of nitrogen. Therefore, jet pumping technology was applied to offload the well.

A jet pump was run in the well on tubing, which was equipped with a bottomhole assembly (BHA) for a downhole jet pump. It was installed in a free-style after opening the swab and master valve of the Christmas tree. Once, the jet pump properly seated in the BHA housing, high pressure power fluid was pumped into the wellbore to lift the kill fluid.

Production results indicate that the killed well was successfully offloaded with cumulative production of 690 BPD, which was higher than the targeted production rates evaluated for this well. Freestyle jet pump deployment has achieved the expected performance and reliability. Moreover, the jet pump can easily be re-optimized by reversing it out to change the nozzle and/or throat without requiring a slick-line job. Hence, the jet pump was found to be the most economical artificial lift method and the trial achieved more than expected results.
Saving Rig Time on Exploration and Development in Deep Gas Wells with an Innovative Approach to Test and Prepare Liners Prior to Completion
Authors: Obari Wahid , Hegazy Mohamed , Ali Hasan , Markabi Mazen , AlAwfi Mohammed R. , Nafi Mohamed Khalil , Al-Fakih Abdulqawi
Published: October 2018

When deep gas drilling in the Middle East, the well completion operation is considered one of the most critical phases of the well construction process. This is due to the series of runs required in order to prepare the well for the lower and upper completions while ensuring well integrity and well barriers. The well completion preparation and complex cleaning requirements are time consuming, representing up to 16% of the total well time. This typically requires multiple clean-up runs after cementing the lower completion (production liner) and before running the upper completion. These additional trips not only consume rig time, but expose the operation to health, safety, and environment (HSE) and non-productive time (NPT) related problems.

Conventional operations, in some cases, may require up to six separate trips to set completions in the well. These extra trips can be reduced by combining different technologies based on specific completion applications to execute the necessary tasks while eliminating unnecessary working time from the drilling operations and the associated cost to a well.

Addressing the challenges associated with the wells in the Middle East required the development of a series of tools and procedures to optimize the operation by completing the required tasks in a single combined cleanout BHA. This paper will provide details about how the operation was successfully performed and can be recreated for other wells experiencing the same challenges.

This paper includes the procedures and the description of tools used to combine multiple runs into one single clean out BHA, which saved 3 to 5 days of rig time per well. In addition, it will review the challenges faced in developing and executing this novel approach to prepare the wellbore for the upper completion and the possible total savings.
Use of NMR and core flow to study the solid invasion in sedimentary rocks – Insights on drilling mud design
Authors: Kesserwan Hasan , Al Tawat Najeeb , Jin Guodong
Published: October 2018

The invasion of solids in the drilling mud into the pay zones have significant consequences on reservoir evaluation and production, hence composing a substantial challenge for the mud design. In principle, the mud contains solid particles denoted as bridging materials that are utilized to build up a mudcake at the wellbore to minimize the invasion of solids into the formation. The failure to build up proper mudcake might drive serious formation damage i.e. serious porosity and permeability reduction that are not reversible.

The purpose of this work is to characterize the effect of the particle size of the bridging materials on the integrity of the mudcake and its influences on filtrates invasion. An integrated approach is introduced combing formation damage experiments at reservoir conditions and Nuclear Magnetic Resonance relaxometry (NMR) to monitor any change in the formation properties. The mud flow experiments were performed on two sandstone and one carbonate rocks with two drilling muds in which the size of the carbonate particles was varied, however all the other mud properties were kept fixed. The barite particles are utilized to simulate the solids invasion. The obtained results showed that the growth of the mudcake is independent of the mineralogy of the rock, though, its porosity and permeability are key elements in determining the proper sizes of the bridging materials.
Pore Pressure Prediction While Drilling Using Fuzzy Logic
Authors: Abdulmalek Ahmed S , Elkatatny Salaheldin , Abdulraheem Abdulazeez , Mahmoud Mohammed , Abdulwahab Z. Ali , Mohamed I. M.
Published: October 2018

Formation pressure is the main function that affects drilling operation economically and efficiently. Knowing the pore pressure and the parameters that affect it will help to reduce the cost of the drilling process. Many empirical models reported in the literature were used to calculate the formation pressure based on different parameters. Some of these models used only drilling parameters to estimate pore pressure. Other models predicted the formation pressure based on log data. All of these models required different trends such as normal or abnormal to predict the pore pressure. Few researchers applied artificial intelligence (AI) techniques to predict the formation pressure by only one method or a maximum of two methods of AI.

The objective of this research is to predict the pore pressure based on both drilling parameters and log data namely; weight on bit (WOB), rotary speed (RPM), rate of penetration (ROP), mud weight (MW), bulk density (RHOB), porosity (ϕ) and compressional time (Δt). A real field data is used to predict the formation pressure using Fuzzy Logic (FL) which is one technique of AI.

Fuzzy Logic (FL) tool was compared with different empirical models. FL method estimated the formation pressure with a high accuracy (high correlation coefficient (R) of 0.998 and low average absolute percentage error (AAPE) of 0.234%). FL outperformed all previously published models. The advantage of the new technique is its simplicity, which represented from its estimation of pore pressure without the need of different trends as compared to other models which require a two different trend (normal or abnormal pressure).