bluuebunny/crossref_metadata_2025 huggingface dataset:
Reducing Drilling Risks in Highly Over-Pressurized Quintuco-Vaca Muerta Formation, a Case History in Neuquén Basin /Argentina
Authors: Frydman Marcelo , Acevedo Andres , Castellanos Jose Miguel , Casanova Ocdomar , Hasbani Jose , Gutierrez Oscar , Giroto Gaspar
Published: October 2018

Different oil operators have faced technical and economic challenges while drilling in Neuquén basin. Drilling in a tectonic active setting creates problems ranging from influxes and stuck pipe incidents to circulation losses. The presence of natural fractures with an abnormally high pore pressure environment in Quintuco formation increases the gas kicks risks during drilling. Drilling nearby wells has evidenced many severe events, like many days to control a hydrocarbon influx with simultaneous losses. Stuck pipe is the responsible for lost BHAs and considerable NPT spent on freeing the pipe, performing additional wiper trips and hole cleaning. Minimizing non-productive time associated with wellbore instability reduces the risk of dangerous accidents at the wellbore site and it is required to complete the well on time and within the budget. This article describes a methodology to reduce drilling risks, in complex pore pressure conditions at Quintuco formation in Neuquén Basin. The proposed method is based on two main assumptions: the 3D pore pressure characterization based on elastic wave velocities on two different levels in Quintuco formation; and the intensity of the influx events is characterized by the presence of fracture corridors. The value added by the integrated team's efforts was demonstrated by drilling the next two wells with significant reductions in costs and nonproductive time.
Predicting Hydraulic Fracture Geometry and Well Performance in Unconventional Reservoirs using the Multilayer Discrete Fracture Network
Authors: Pankaj Piyush
Published: October 2018

Naturally fractured shale reservoirs are characterized by a complex 3D discrete fracture network (DFN). DFN density in different stratigraphic layers imposes variability in hydraulic fracture geometry as the hydraulic fracture propagates in the laminated shale reservoirs. The study presented in this paper aims to parametrically determine the hydraulic fracture geometry and consequent well production when varying densities of DFN interact with the propagation and growth of hydraulic fractures.

A 3D multilayer DFN (MDFN) is discretized in vertical grid elements distributed in layers of the formation. This is represented in a geocellular grid model with varying DFN sets in multiple layers. A new hydraulic fracture propagation model with stacked height has been utilized to determine the interaction of the hydraulic fractures with the DFN in all different layers. The vertical variation of the DFN causes more complex fracture propagation because it accounts for the fracture crossing criterion apart from the stress profile variation in layers and the stress shadow impact. Comparison of such complex hydraulic fracture geometry with the simplistic average 2D representation of the DFN reveals the geometry difference. This is further coupled to reservoir simulation in numerical engines to determine the difference in production performance. Finite element geomechanical simulations are made to predict microseismic events, which are then compared to the acquired microseismic data to validate the hydraulic fracture geometry.

Hydraulic fracture geometry was found to differ when an MDFN approach was taken as compared to simplistic single-layer DFN (SDFN) interaction. Production performance of the fracture geometry obtained by considering an MDFN was therefore more realistic. The simulated microseismic data also exhibited a much better match to the acquired microseismic data when an MDFN was used for modeling. Visual analytics tools for comparison of observed microseismic event distribution with predicted microseismic data in the model show errors ranging from 16% to 24% for different view representations. As a conclusion of this study, it was evident that wherever applicable, an MDFN approach should be used to determine the well completion performance. However, there is some scope for improving the modeling of hydraulic fracture interaction with natural fractures by incorporating the dip angle of the MDFN for computing the crossing criteria.

This study represents the first time a more-robust modeling of the interaction of hydraulic fractures with a 3D MDFN was achieved using complex fracture models to determine the impact on productivity. Finite-element-computed microseismic data allowed further validation. Operators can use the approach described in this study to predict their well performance more accurately in complex fracture reservoirs.
Modeling of Conformance Improvement through Smart Polymer Gels
Authors: Temizel Cenk , Canbaz Celal Hakan , Putra Dike , Najy Anas K. , Alklih Mohamad
Published: October 2018

Several studies have indicated polymer flooding to be an optimal enhanced oil recovery (EOR) strategy in fields with oil viscosities between 10 – 150 mPa.s. In the current oil price environment maximizing the output from exisiting fields, using the ideal EOR operation pertinent to each reservoir, is of increased importance. In addition, with almost half of the total global oil production for the coming decades projected to come from EOR operations, it is essential to select the right strategy for each field. For fields that have oil viscosities above 150 mPa.s, mobility ratio of the polymer containing injectant is an inhibiting factor to the polymers injectivity and pumping efficiency, and hence polymer flooding is not a viable EOR strategy in such fields.

Supramolecular systems are a viable alternative to conventional polymers used in polymer flooding, mainly due to their high resistance to temperature and salinity. A unique feature of these systems is its reversible viscosity, using which system viscosity can be adjusted from low values during injection to high values prior to oil contact within the reservoir. Supramolecular systems are highly resistant to degradation from shear and temperature due their inherent property of disassembling, when exposed to high shear and/or temperature, and re-assembling. This property is useful in restrictive environments such as flow through narrow channels, where supramolecular systems disassemble (molecular scission) and reassemble, thereby maintaining its molecular properties in a "self-healing" manner.

In this study, modeling and simulation of these "self-healing" supramolecular systems have been conducted to compare its displacement efficiency compared to conventional polymer systems. They have the potential to be applied to multiple types of reservoirs including those with thin layers and permafrost conditions. From the results of this study it is evident that supramolecular systems offers field operators considering polymer flooding a cost-effective, smarter and technologically feasible EOR strategy.
Diversion and Keys to Stimulation Success or Failure
Authors: Fragachan Francisco E , Huang Jian , Safari Reza , Aubry Eric , Thirion Aurelien , Benquet Jean-Claude
Published: October 2018

The ultimate goal of diversion applications is to enhance contact of the stimulation fluid with the reservoir rock in such a way to maximize the conductive reservoir volume. Unfortunately, intentions to simplify diversions with rule of thumbs, trial and error, and pump and hope have generated uncertainties and slowed the impact in stimulation efficiency and production enhancement that this technique is capable of generating.

Fluids introduced into a reservoir for stimulation typically take the path of least resistance and therefore frequently go into areas where there are open flow paths. In many cases, those existing flow paths are neither the areas you would want to stimulate for increased production, nor areas from which formation damage will need to be removed. The success of a hydraulic fracturing or acidizing operation depends on maximizing the contact between the stimulation fluid and the intact rocks. To achieve this goal, existing fluid paths must be efficiently plugged to divert the fluid towards intact or under- stimulated rock for efficient application, which in turn maximizes the BOE (barrels of oil equivalent) returned from the stimulation treatment relative to unit cost.

Although industry has been deploying this technology on a more widespread basis recently, they have not been as focused on the underlying mechanisms, physics and controlling parameters which ultimately govern the success of the stimulation event.

This paper will present a comprehensive discussion around missing factors associated with jamming and plugging efficiency, particle size, particle shape, frictional parameters, particle concentration, opening geometry, rate during placement, and particles ratio. It will clearly highlight the importance of understanding the physics and mechanisms associated with a complex diversion process requiring a rigorously engineered approach.

Multiple experiments were reviewed to quantify and understand the effect and importance of the different key factors that dictate the overall goal of a successful diversion treatment. In fact, an analytical model has been developed, verified with advanced numerical simulations and calibrated with experimental results to optimize the operational parameters required for efficient diverter displacement; including adjusting the displacement rate during diverter injection and also determining and adding the required volume of spacer to minimize particle dispersion, which ensures that the diverter pill arrives at the required site intact and as designed. The proposed numerical and analytical engines are presented within the design engineering process to better enable and achieve the necessary pressure buildup required for efficient fluid diversion.
Can Solvent Injection be an Option for Cost Effective Enhanced Oil Recovery?: An Experimental Analysis for Different Oil and Rock Characteristics
Authors: Babadagli T. , Cao N.
Published: October 2018

We performed a set of experiments on vertically situated sandpack models. Different slug sizes of water and solvent (heptane used in the experiments) were tested for 2,000 cp heavy-oil. As a benchmark, tests were also performed for 14 cp light oil for comparative analysis. In addition to the technical feasibility, an economic analysis was performed considering the amount of solvent injected and oil and solvent recovered. Experiments were repeated for oil-wet systems. For both light and heavy oils, starting the process with the solvent was feasible in the short run technically and economically. If the process starts with water, excess amount of it occupies the largest pores and hinders solvent-oil interaction for mixing and oil displacement. This was true especially if the rock is both oil-wet and heavy, which yielded faster recovery and higher ultimate recovery than the water-wet case. The time for switching to solvent injection is more critical in the heavy-oil case as it is more sensitive to the amount of existing water in the system. As oil becomes heavier and if the rock is water-wet, starting the process with waterflooding is not suggested. In this case, more solvent needs to be injected in the first cycle compared to oil-wet systems. Due to partial miscibility and more gravity stable nature, solvent retrieval and sweep with water can be more effective in case of heavy-oil compared to light oil (fully miscible case) and, as a result, can be even more profitable. This is highly critical in exploitation of heavy-oil reservoirs if thermal options are limited and greenhouse gas emission is a concern.
A Robust Nitrogen-Digestion Method to Determine the Concentrations of Polyacrylamide-Type Polymers
Authors: Hou Jian , Han Ming , Fuseni Alhasan
Published: October 2018

Polyacrylamide-type polymers are widely used in polymer flooding techniques for mobility control. To monitor the performance of a polymer flooding process in either field application or laboratory testing, it requires the accurate determination of polymer concentrations in the effluents. This paper presents a robust nitrogen-digestion method to determine the concentrations of various types of polymers such as hydrolyzed polyacrylamides, sulfonated polyacrylamides and cationic polyacrylamides.

Different from the classical nitrogen-bromination method used to identify polymer concentrations, the nitrogen-digestion method is based on the digestion of amide groups in the polymers as free nitrate ions using digestion device operated at 120ºC. The resultant solutions were measured by a visible light spectrophotometer. The nitrogen contents as measured by absorbance values of the solutions are used for the calculation of the polymer concentrations. The average testing time for each sample is less than 5 minutes.

Seven polymer samples from three different polymer types were investigated. The experimental results show good correlations between nitrogen content and absorbance values and the resulting concentration for each polymer sample studied. As the chemical structures of polymers might be altered in the application process, such as hydrolysis of amide groups to hydroxyl groups, the concentration results obtained could be interfered with. Therefore, the infrared (IR) method was used to revise the concentrations obtained by nitrogen-digestion method. A normalized correlation as a rule-of-thumb was set up to categorize the polymer type and determine the polymer concentration. In addition, it was also noted that the measurements of polymer concentration using the nitrogen digestion method are not influenced by the salinities of make-up brines.

This paper presents an accurate, portable, and fast way to determine the polymer concentrations in brines. It is of particular importance for field operations.
Carbon Intensity: Comparing Carbon Impacts of Middle East and US Shale Oils
Authors: Meehan D. Nathan , El-Houjeiri Hassan M. , Rutherford Jeffrey S.
Published: October 2018

Carbon intensity (CI) is a quantitative measure of the carbon generated per unit of energy and is a useful way to compare alternative sources of energy or even various crude oils. The CI of oil and gas production varies widely across global oil plays. Life cycle extraction from some unconventional plays (e.g., tar sands) have some of the highest CIs, but even many North American shale plays have relatively high carbon intensity. Middle East crudes range from some of the lowest to some of the highest global values of CI. Flaring and venting of associated or non-associated natural gas dramatically increases CI.

This paper applies peer-reviewed processes across broad averages of shale activity in North America and compares them with Middle East activity. We perform well-to-refinery calculations of CI for major unconventional oil plays in North America and Middle East major producing countries. This approach accounts for emissions from exploration, drilling and completions, production, processing, and transportation. The analysis tool is an open-source engineering-based model, developed at Stanford University, called the Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions by using up to 50 parameters for each modeled field. Data sources include government sources, technical papers, satellite observations, and commercial databases.

Applied globally, OPGEE estimates show the highest values are in areas with extensive flaring of natural gas and for very heavy crude oils. Heavy oils requiring large energy inputs (e.g., steam flooding) and/or the use of light hydrocarbon diluents for transportation have much higher values of carbon intensity. Saudi crude production, analyzed from public sources, has some of the lowest CI regionally and globally.

Examples illustrating how OPGEE can be used to evaluate the CI of public policy actions are provided. Further sensitivity analyses to pad drilling and improving well performance are shown, and the CI impacts associated with hydraulic fracturing.

While Middle East crude will remain vital to global supplies, unconventional production, especially from light tight oil (LTO), is the most significant new source of fossil fuels in the last decade. Under almost any conceivable carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments and regulators must avoid "locking in" the development of sub-optimal resources and provide incentives for LTO operators to manage resources sustainably. Oil producers must prepare by eliminating development of marginal projects, eliminating flaring, optimizing hydraulic fracture treatments, increasing the use of pad drilling, using improved recovery methods (e.g., enhanced oil recovery using anthropogenic CO2), reducing energy use, and eliminating unnecessary gas waste.
Effect of Data Errors on Multiphase Flow Correlations
Authors: El-Moniem Mohamed A. , El-Banbi Ahmed H.
Published: October 2018

In absence of downhole permanent gauges, multiphase flow correlations are widely used to predict well flowing pressures and production under variety of conditions. They also have wide applications in nodal analysis and artificial lift optimization.

In our previous work (SPE-175805), we collected a large database of more than 3000 multiphase pressure points and tests. We used this large database to develop guidelines to select the most accurate correlations for different pipe and flow conditions. Typically, there are close to 20 input parameters used in the calculations of multiphase flow correlations. In this study, we used sensitivity analysis techniques with our large database to determine which input parameters affect the multiphase flow correlations results for different pipe and flow conditions. Among these important input parameters are producing gas-oil ratio (GOR), API, gas specific gravity and tubing roughness. For each of the important input parameters, we change the value of the input parameter within the measurement accuracy in the field and find out their effect on the calculated pressure in comparison with the measured pressure.

We categorized the large database into clusters representing different pipe and flow conditions, then used a commercial pipe flow software to model these wells. We then performed hundreds of sensitivity studies on almost all input parameters for oil wells. It was observed during the study that several parameters have significant effect on multiphase correlations results. These effects were different for low and high production rate wells and low and high GOR wells. For example, accuracy of API was found to have low effect on results. However, GOR had significant effect on results. Pipe roughness was found to be much less important in oil wells especially at low production rates and at low GOR.

Based on the results of the sensitivity studies for the large database, we developed guidelines for which parameters are important for which wells and under what conditions. The guidelines will help engineers working on developing multiphase flow models for wells focus on obtaining good values for the most important input parameters.
Well Data Transfer between Corporate Database and Vendor Database
Authors: Wei Xinwei , Amer Mustafa M. , Rushood Ibrahim S. , Alsinan Hadi H.
Published: October 2018

It is common nowadays in the O&G industry that operators maintain their own data repository for drilling and workover operations, develop applications on top of it. Meanwhile, operators still use service companies/vendors specialized applications for various business needs. Data integration becomes more important for utilizing existing data in operator’s data repository in vendor applications and vice versa.

An approach to transfer deviation survey data from corporate database directly to vendor database was attempted, it has gone through two major phases: from manual to automated process. The automated data transfer process synchronize deviation survey data between two databases on a daily basis for over a year and stable.

The success of deviation survey data transfer from corporate database to vendor database laid the foundation to establish common data structures and enable other data types to be added in the data transfer process. With more data available in vendor application database, engineers have changed the way they obtain well data information, and saved lot effort and time for data input for planning their wells.
Enhanced Heavy Oil Recovery by Thermal-Different Aqueous Ionic Solutions-Low Salinity Water Flooding
Authors: Al-Saedi Hasan N. , Flori Ralph E. , Brady Patrick V.
Published: October 2018

In this study, we propose to quantify a control of water chemistry on water-rock interactions and wettability alteration during Lo-Sal water-flooding of sandstone cores containing heavy oil. We intended to identify the dominant process of wettability alteration through considering all possible water-rock interaction mechanisms simultaneously. Water chemistry partially determines the dominant wettability alteration. This includes salinity, type of ions, and possibly pH.

The effect of the potential determining ion towards sandstone ‘calcium ion’ is presented in this work. The ultimate oil recovery for the core saturated in normal Ca2+ concentration at higher temperature was higher than the core saturated with double Ca2+ at the same temperature. The divalent cation (Ca2+) concentration was then doubled in the aging water, resulting in a lower oil recovery. The thermal technique seems to be related to the chemistry of the water, meaning that the injected hot water must be tuned to the proper chemical composition. Desorption of Ca2+ is associated with pH jump and thereby increased microscopic sweep efficiency, and it seems to have a large impact on LS water EOR heavy oil.
Zero Solid Invasion Water-Based Drilling Fluid
Authors: Jafarov Tural , Elkatatny Salaheldin , Al-Majid Abdulaziz , Mahmoud Mohamed
Published: October 2018

Reducing the filtrate volume and eliminating the solid invasion is very important and critical in drilling tight reservoir. This will eliminate water blocking which is the common problem in drilling tight gas formation.

The objectives of this study are to evaluate the effect of using sodium silicate, assess the changes of the rheological properties of water-based drilling fluid, determine filtrate volume and filter cake thickness, and optimize the concentration of sodium silicate to be used.

The obtained results showed that there was no effect of adding sodium silicate to the drilling fluid on density and pH. At room temperature, the optimum concentration of sodium silicate was 0.075 wt.% wt. which no change was observed in the yield point plastic viscosity ratio and at the same time, the plastic viscosity, yield point, and gel strength were enhanced. At higher temperature 120 and 170℉, the optimum concentration of sodium silicate was 0.075 wt.% which enhanced the rheological properties of the drilling fluid. Sodium silicate worked as a catalyst and as a result, it enhanced barite solubility at 200℉. The cumulative filtrate volume was decreased by 53% when using 0.075 wt.% of sodium silicate and the filter cake thickness was decreased by 65%. The retained permeability was 100% and the CT number before filtration and after removal was very closed, confirming no solid invasion was observed in the core.
Optimizing the Gel Strength of Water-Based Drilling Fluid Using Clays for Drilling Horizontal and Multi-Lateral Wells
Authors: Alakbari Fahd , Elkatatny Salaheldin , Kamal Mohamed Shahrazad , Mahmoud Mohamed
Published: October 2018

Drilling fluid constitutes an important part of the drilling operations. Drilling mud is circulated into the wellbore to minimize the formation damage, transport cuttings from the bottom to the top of the well, cool and lubricate the bit, and maintain the stability of shale formations. Gel strength property of drilling fluids plays a key role in drilling multilateral and long horizontal reservoir sections. Losing the gel strength will accumulate drilled cuttings and as a result, sticking of the drill string. Solving this issue takes a long time and increase the total cost of the drilling operation. It was observed that, by increasing the temperature to 200°F, the gel strength of calcium carbonate water-based drilling fluid reached zero lb/100 ft2.

The objectives of this paper are to: (1) determine the rheological properties of calcium carbonate water- based drilling fluid over a wide range of temperature, (2) assess the effect of using clays (bentonite) to solve the gel strength problem associated with the current field formulation of calcium carbonate water- based drilling fluids, and (3) optimize the weight percent of bentonite. Rheological properties such as the apparent viscosity, plastic viscosity, yield point and gel strength were measured by using a high-pressure high-temperature rheometer.

At low temperatures (85°F), the calcium carbonate water-based drilling fluid showed no change in the gel strength with time. However, at high temperatures, the gel strength starts decreasing with time. Rheological properties confirmed that the gel strength of the calcium carbonate water-based drilling fluid reached zero lb/100 ft2 by increasing the temperature to 200°F. This issue was solved by adding different concentrations of bentonite. The bentonite concentration was varied from 3 wt.% to 10 wt.%. At low bentonite concentrations (3.33 wt.%), the gel strength still reduced with time. At high bentonite concentration (10 wt.%), the gel strength increased with time. The optimum concentration of bentonite was 6.66 wt.%, which yielded a flat rheology profile of the gel strength. These results confirmed that the rheological properties of the water-based drilling fluid were optimized by using clays (bentonite).

The novelty of this research is the complete investigation of the drilling fluid properties especially the gel strength with time over a wide range of temperature. The results obtained can leads to the development of a cheap solution without any side effect.
A Generalized Varying Oil Compositions and Relative Permeability Screening Tool for Continuous Carbon Dioxide Injection in Naturally Fractured Reservoirs
Authors: Hamam Hassan , Ertekin Turgay
Published: October 2018

Carbon Dioxide (CO2) injection is a viable technique with huge potential if employed efficiently in naturally fractured reservoirs. However, extensive computational resources are needed to evaluate and consider candidates for continuous CO2 injection projects. In this study, a new workflow is developed that captures universal fluid compositions and relative permeability data for fields undergoing continuous CO2 injection in naturally fractured reservoirs.

Injection design schemes and parameters for continuous CO2 for hypothetical reservoir types are constructed using a miscible, dual porosity, compositional reservoir simulation model. An algorithm is developed to capture varying fluid compositions and relative permeability data for the data set used in this study. Data collected from reservoir simulation cases are used to construct two Artificial Neural Network (ANN) based proxy models. Namely, a proxy for performance prediction that utilizes specific injection design parameters to predict reservoir performance and an inverse proxy for injection design that provides injection design scheme for a desired reservoir performance.

The constructed ANN’s predictability is assessed through its capability of predicting blind test data within a specified tolerance. The proxy based models were capable of predicting, within an acceptable degree of error, the oil and gas production profiles as well as injection design parameters of well spacing, CO2 injection rate, and CO2 injection duration of a field undergoing continuous CO2 injection. The constructed networks were tested with real data from Twofreds field in Texas that has been undergoing continuous CO2 injection since 1974. The constructed proxy based models were able to overcome limitations imposed by the complexity of handling different compositional reservoir fluids and relative permeability data. The new methodology sets a new benchmark for universal proxy modeling as it incorporates composition based reservoir fluid and relative permeability data.

The approach presented overcome existing limitations in handling compositional reservoir fluid variations as well as relative permeability in universal workflows.
Surmounting Paucity of Data in Hydraulic Fracture Designs: Case Studies From the Permian Basin
Authors: Elsheikh Ellewa Ahmed , Amao Abiodun Matthew
Published: October 2018

The design of an optimal and effective hydraulic fracture treatment requires lots of input data, spanning the spectrum from rock properties, fluid properties, well-logs, Geomechanics to economics. However, operators tend to cut costs by reducing expenditure on data acquisition. This paper discusses the challenges of hydraulic fracture treatment design in such cases and presents procedures that can be used to effectively design fracture treatments where completion engineers may not find the needed data from obvious direct sources. Recommended solutions for obtaining data from indirect sources to fill the gap of unavailable data are presented. In addition, the adequacy of such designs is evaluated and compared to actual hydraulic fracturing treatments pumped.

Treatment designs pumped for several stages of a fractured well located in the Permian Basin of West Texas, US were investigated. This is a geologically complex environment with huge variation in lithology and formation properties. The well under study had only the drilling records and the conventional logs suite (gamma ray, neutron, density, pe and resistivity). However, to finalize other required data for the treatment design i.e. reservoir permeability, geomechanical properties, etc., the design inputs were obtained through the creation of synthetic logs. Sonic logs were generated using models created from log data from off-set wells. In addition, geological properties of the candidate formation were reviewed and used for data calibration. These collected data were then used in designing the hydraulic fracture treatment using industry standard fracture design software, FRACPRO, to obtain the design outcomes. The treatment was designed and simulated using the same fluid systems and proppants as was used in the actual pumped treatments. Finally, the design results were compared to the field treatment data from the fractured well.

Compared to real-time fracturing results, the pressure and rate profiles were close match to those generated by the software. This shows the possibility of conducting a proper fracturing design using limited acquired data. However, these results depend mainly on the accuracy of the well logs used to generate the mechanical properties, and the available data about the formation from previous treatments. Moreover, the accuracy of fracturing simulation when all needed data are obtained by direct measurements should be compared to situations with paucity of data, to determine how to improve the results obtained.

The information presented in this work will help engineers deliver economic and optimal hydraulic fracture treatments especially in this present low oil price regime. Also, informed and appropriate decisions can be made regarding optimized data acquisition in candidate formations for better planning and maximum profitability.
Natural Fractures Permeability in Liquid Reservoirs During Non-Darcy Regime
Authors: AlSinan Marwah
Published: October 2018

Fluid flow in Fractures is the main transport and production mechanism in naturally and hydraulically fractured reservoirs. Thus, understanding the various non-Darcy flow regimes is critical for naturally fractured reservoirs, particularly for gas and near the wellbore. While the Forchheimer model for non- Darcy flow has been confirmed numerously, models describing flow behavior prior to the Forchheimer model are still controversial. Also, since the conductivity of a fracture network is dependent on the permeability of the individual fractures, the relationship between fracture transmissivity and morphology requires investigation.

In this paper, a systematic analysis of experimental data, spreading over a vast range of Reynolds number (Re), was carried out to assess the encountered flow regimes. The analysis was conducted using three diagnostic plots, which are: flow rate vs. pressure gradient and first and second derivatives of normalized permeability vs. Re. The analysis confirmed the Mei and Auriault (1993) and Forchheimer models during the weak and strong inertia regimes, respectively. Also, the Forchheimer dimensionless coefficient demonstrated an increasing trend when plotted against the Relative roughness, which was defined as the mean over the standard deviation of aperture. A universal correlation for the dimensionless Forchheimer coefficient could not be established from the plot. Therefore, we proposed investigating other geometrical parameters, which include contact areas, anisotropy, surface roughness, and aperture waviness to improve the correlation. Deriving a robust description of the Forchheimer dimensionless coefficient in terms of fracture relative roughness, will improve practices, such as well testing interpretation, history matching, and production forecasting of oil and gas.
Effect of N2 on CO2-Foam Assisted Enhanced Oil Recovery in Sandstone Reservoir
Authors: Hassan Mohamed , Gajbhiye Rahul
Published: October 2018

The global need for CO2 sequestration and associated advantages made CO2 gas injection as one of the important enhanced oil recovery (EOR) technique. The higher solubility of CO2 in oil, less injection pressure and miscibility makes it a favorable choice for EOR processes, but it suffers from high mobility and gravity override results in lower ultimate recovery. The high mobility and gravity override can be minimized by generating the CO2 foam with the aid of a surfactant. However, CO2 is unable to generate the foam/stable foam above its supercritical point (1100 psi, 31°C). These difficulties with CO2 foam is overcome by adding N2 in a small fraction to enhance the foam generation of CO2 at supercritical conditions. This study shows how the addition of small quantity of N2 helps in generating the CO2 foam and performance of the novel CO2/N2 mixture foam in enhanced oil recovery.

To investigate the performance of CO2/N2 foam, core-flooding experiments were conducted at elevated pressure and temperature condition (higher than supercritical CO2 – 50°C and 1500 psi) in sandstone cores. Fluorosurfactant (FS-51) was used as a foaming agent and n-decane was used as model oil in all the experiments. The selection of foam quality and N2 fraction was optimized based on foam generation and stability tests. Every gas or foam flooding was preceded by seawater injection to simulate the behavior in the reservoir.

The results from the core-flood experiments showed that the CO2 and CO2/N2 foam flooding recovered an additional 34-40% of Original Initial Oil in Place (OIIP) indicating that foam flooding succeeded in producing more oil than pure CO2 gas injection processes. Additionally, the performance CO2/N2 foam injection was better than CO2 foam injection for delaying the breakthrough.
Overcoming Challenges in a Multi-Rig Turnkey Development Drilling Project Resulting in Top Level Performance
Authors: Al Fakih Abdulqawi , Ahmad Bilal , Javaid Muhammad O. , Yakhlef Redha , Stoyanov Emil K. , Crighton Alan , Ouahrani Louanas
Published: October 2018

There are several challenges when establishing a multi-rig operation in a new drilling or workover project. People from different companies and diverse backgrounds will have to work together and integrate with each other in a new working environment. These challenges are compounded when the drilling contractor is new to the country, rigs are newly built and ‘linguistic differences’ impacting efficient communication that exist between the staff of the drilling contractor and the project team.

This paper reviews the start-up and the learning curve for a project of four rigs to drill horizontal and vertical wells under LumpSum TurnKey (LSTK) contract. It presents the measures implemented to create a cohesive team and to accelerate learning. Also, it focuses on rig management, safety assurance and performance driving and monitoring.

The main challenges are highlighted, and the step by step solutions taken are described. The results discussed are showing the progressive improvement from a quality and safety standpoint. Drilling data from over 100 wells is analyzed to illustrate how workflows and innovative technologies contributed to progressively improve well delivery and surpass the established benchmarks. Finally, the paper discusses the merits of integration between the client, service companies and the drilling contractor, presenting a clear case where the whole is greater than the sum of its parts.
Review of Iron Sulfide Scale: The Facts & Developments and Relation to Oil and Gas Production
Authors: Okocha Cyril , Kaiser Anton , Wylde Jonathan , Petrozziello Lena , Haeussler Matthias , Kayser Christoph , Chen Tao , Qiwei Wang , Chang Frank , Klapper Markus
Published: October 2018

Oilfield iron sulfide (FeS) control and prevention have been mostly proprietary with several disparate solutions. Frequently FeS control involves milling, jetting, acid soaking, pulling and replacing tubing and manually cleaning tanks, vessels, separators and pumps. These methods are costly, wasteful and strenuous. This paper reviews the latest developments in oilfield FeS researches with an attempt to integrate viable solutions and expose unworkable practices.

In this work, we review and evaluate the most common FeS prevention and control solutions in an attempt to summarize the state-of-art FeS mitigation technologies. We have a closer look on FeS formation and control as well as potential integrated solutions. The paper reviews and differentiates treatment solutions between corrosion byproduct and FeS scale deposition from formation.

Most FeS scales have generally been treated as the same, using various treatment methods. Complex FeS polymorphs have resulted in different outcomes. This work focuses on different treatment options that assert to work for all FeS scale not differentiating between corrosion-byproduct and reservoir formed scale.

Successful case histories and suspected FeS polymorph are presented in this paper next to discussion of the model used to predict severity of the deposition and analyze the treatment design. FeS formation and deposition is evaluated, especially crystallography and fundamental studies into mechanistic aspects of FeS precipitation and how it relates to oilfield FeS precipitation.

In this paper state-of-art FeS scale research is summarized and differences to normal scale types are presented. Mineral scale in the true sense of going through the stages of nucleation, pre-crystallization, crystal growth, agglomeration and deposition. This is an important step change in consolidating all the disparate areas of FeS studies into an advanced solution focused approach. If FeS scale is considered a mineral scale then solutions such as scale inhibitor applications (continuous injection and squeeze) that work for common mineral scales should work for FeS deposition as well. Thereby moving FeS research from a relatively empirical level with vastly different approaches that are mostly unrealistic into solutions that will be viable in the oilfield.
First Use Worldwide of a Conventional Stage Tool Integrated With an Inflatable Packer Element for Casing While Drilling
Authors: Al Fakih Abdulqawi , Cengiz Husnu Ozgur , Aldape Alberto Gomez , Halma Jeremy , Alatiyyah Ahmed Subhi
Published: October 2018

The sustained impact of low oil prices continues to keep pressure on drilling economics whereby well construction teams must combine techniques to decrease Non Productive Time (NPT) therefore reducing cost, and improve drilling performance.

A casing while drilling approach was proposed in the top sections where borehole instability typically occurs after having a total loss circulation which increases the risk of mechanical stuck pipe. The presence of a water aquifer in the same section imposes the need for a cement stage tool and an isolation packer. A 9-5/8in trial job was planned and executed where drilling forces simulations were performed for the 9- 5/8in casing with buttress connections and conventional cement stage tools, packer elements and centralization to identify the maximum forces that could be experienced during the execution. A hazard analysis and risk control with a full contingency plan was performed. Three jobs were carried out after first trial with 13-3/8in casing buttress connections and conventional stage tool with successful results.

This paper describes the methodology and the successful execution of incorporating a conventional cement stage tool and packer element for casing while drilling applications to reduce both NPT and drilling risks as well as maintaining well construction integrity.
A Newly Developed Process for Wellbore Geometry Analysis from a Geomechanical Perspective
Authors: AlBahrani Hussain , Al-Qahtani Adel , Marhoon Zahrah , Hamid Osman
Published: October 2018

The wellbore quality can be affected by a multitude of factors that include drilling operations practices, drilling fluids quality, and geomechanical quality. Low quality wellbores lead to many complications that will result in well completion delay of. One factor of success in drilling operations is minimizing enlargements and tight spots. A new assessment process was developed to understand and analyze the influence of drilling operational practices on the wellbore shape. The analysis helps to identify the root causes of wellbore enlargement and propose mitigation solutions.

More than 20 wellbores have been analyzed. Those wellbores penetrate a carbonate sequence followed by a sandstone sequence. This is to characterize the variations in the wellbore shape, in terms of enlargements and tight spots, against a set of well-defined parameters affecting it. For these wellbores, the mechanical properties and the stresses were estimated to correlate the geomechanical aspects of penetrated formations to the behavior of the wellbore geometry. Cyclic lateral loading of the drillstring, mud-controlled swabbing, and unintentional deviation in some wellbores were also investigated.

The assessment concluded that cyclic lateral loading, due to reaming and vibrations, is a key factor of influence in changing the wellbore shape. Also, the mud-controlled swabbing proved to have a significant role in hole enlargements specifically. This was found to be evident in wellbores that employ highly viscous mud with a 30 min. gel strength of more than 25 lb/ft2. It was also found that using mud with low chloride concentration, below 30 g/L, contributed to the varying geometry of wellbores.

Applying the recommendations generated by this work will help to refine the quality of future drilled wellbores and consequently, mitigate the risks of pack-offs, stuck-pipe incidents, sidetracking, low quality logs, and casing-casing annular pressure. Also, this work will present a new approach for real- time wellbore quality prediction and monitoring using advanced data analytics tools.
Evaluating Wellbore Tortuosity in Horizontal Wells Caused by RSS Steering Mechanism
Authors: Oliveira Victor , Zahrani Bader , Alrushud Albaraa , Mohammad Muntasar
Published: October 2018

This paper describes a new approach to evaluating the effectiveness of the rotary steerable system (RSS) steering mechanism on wellbore tortuosity in horizontal wells. Wellbore tortuosity in drilling applications is defined as any unwanted deviation from the planned well trajectory. As reservoir objectives become more complex and exact, operators increasingly perceive the wellbore tortuosity as a serious concern in the process of drilling, completing, and producing wells.

Strict criteria were set during the classification process; the studied wells have a common geology and trajectory, and they use a very similar bottomhole assembly (BHA) design. The inclination values from the wireline tool are used to illustrate the attainable benefits in terms of wellbore quality and measure wellbore tortuosity. In addition, the wireline inclination data are compared with the actual measurement- while-drilling (MWD) survey to highlight the existence of the micro-dogleg severity (DLS) that cannot be measured by standard surveys.

Due to the theoretical differences in the steering mechanism between the various types of RSS, it has been claimed that utilizing one steering mechanism over another can produce a less-tortuous wellbore. These steering mechanisms have previously been classified as either push-the-bit or point-the-bit mechanisms. The relative merits of a push-the-bit steering mechanism vs. a point-the-bit steering mechanism is an over- simplification; neither mechanism can deliver the premium wellbore quality the industry demands from RSS. The present study introduces the continuous proportional steering method (CPSM), and demonstrates how this mechanism can provide superior wellbore quality by reducing wellbore tortuosity. In addition, a superior inclination hold performance is observed in horizontal sections drilled with the CPSM. Curve intervals are more continuous and smoothly drilled through the planned directional changes.

The research becomes a useful reference to analyze the performance and efficiency of RSS steering mechanisms across drilling and workover operations. Directional drilling service companies are encouraged and challenged to improve the efficiency and accuracy of RSS mechanisms, improving the hole quality and reducing micro-doglegs.
Critical Factors Affecting Pulsed Neutron Saturation Monitoring in Carbonate Reservoirs
Authors: Eltaher Yahia , Ma Shouxiang , AlNasser Mamdouh
Published: October 2018

Pulsed neutron spectral carbon/oxygen (C/O) logging is a widely used shallow measurement for time lapse reservoir saturation monitoring. Because of its shallow depth of investigation, its measurement is affected by several factors among which the near wellbore logging environment is the most important. For example, hole condition, cement quality and fluids in the wellbore have drastic effects on C/O measurement. Some of these effects, such as those due to oil holdup in the wellbore, can be corrected for in the data post-processing. Others might have a permanent imprint on the data, which cannot be removed. It is therefore extremely important to fully understand the effects of the different physical parameters within the wellbore vicinity that might be affecting the measurements.

An extensive study was conducted in a field where reservoir saturation monitoring logs encountered discrepancies in water saturation between open hole and C/O logs, where the latter showed changes in saturation not supported by production history. It was found that one of the main reasons behind this discrepancy is the effect of mud filtrate invasion on the shallow C/O measurement, which varies as a function of timeand rock type characteristics. Other factors, such as wellbore fluid reinvasion effect across zones of perforation, also play a role.

In this paper, it is demonstrated with field examples the effect of mud filtrate on C/O logs and define criteria used to diagnose this phenomenon. It is also highlighted other factors affecting C/O measurement such as wellbore fluid reinvasion and cement condition. Last, we present recommendations and best practices to conduct a more representative reservoir saturation monitoring.