bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental and Computational Study of Flow Characteristics in a Drilled Perforated Core
Authors: Sun Datong , Satti Rajani , Ochsner Darren , Sampson Tim , Li Baoyan , Gladkikh Mikhail 
Published: June 2014

Abstract
In recent years, the oil and gas perforation industry has seen the growth of several perforation flow laboratories to experimentally measure the flow characteristics of perforated cores. In such experiments, the determination of core flow efficiency (CFE) depends on the theoretical flow rate in addition to the measured flow rate. Usually, an average core axial/radial permeability is used to calculate the theoretical flow rate, thereby neglecting the heterogenic/anisotropic nature of the core. In this study, we examined the significance of considering the core heterogeneity/anisotropy through experiments and a computational fluid dynamics (CFD) approach.
In this study, a cylindrical Berea sandstone core sample (7-in. diameter x 30-in. length) is drilled axially using a custom drill, with a 1-in.-diameter hole and 3.25-in.-length increments through the core. Flow characteristics were measured under axial flow boundary conditions for each drilling depth of the core. Further, multiple axial/radial core plugs were extracted and routine core analysis was conducted on these core plugs to measure the localized porosity and permeability. Subsequently, the experimental data was complemented by conducting numerical simulations using commercial CFD software for each perforation length.
For the case where the average axial permeability from experiments was used directly in the CFD simulations, significant discrepancies in equivalent permeability were found between experiments and simulations. Subsequently, CFD simulations using the localized permeability of axial core plugs showed good agreement with experiments. It was also found that CFD results using the localized permeability of all axial and radial core plugs provided similar results as compared to using only the axial core plugs. It can be inferred from the above results that core axial heterogeneity is very important for perforation flow prediction and the anisotropy has minimal effect on the CFD results for this Berea core.
Therefore, this study provides insight into the importance of axial permeability heterogeneity to calculate CFE for a perforated core flow under axial flow boundary condition in the perforation flow lab. It also plays an important role in the development / validation of numerical models and more importantly evaluating shaped charge performance for perforated core /well-scale scenarios.
Hydraulic Fracture Optimization in Unconventional Reservoirs
Authors: Saldungaray Pedro , Palisch Terry T. 
Published: June 2014

AbstractHydraulic fracturing has become a critical component in the successful development of unconventional reservoirs. From tight gas, to oil and gas-producing shales and coal bed methane, resource plays rely on hydraulic fracturing for commercial viability.A primary goal in unconventional reservoirs is to contact as much rock as possible with a fracture or a fracture network of appropriate conductivity. This objective is typically accomplished by drilling horizontal wells and placing multiple transverse fracs along the lateral. Reservoir contact is optimized by defining the lateral length, the number of stages to be placed in the lateral, the fracture isolation technique and job size. Fracture conductivity is determined by the proppant type and size, fracturing fluid system as well as the placement technique.While most parameters are considered in great detail in the completion design, the fracture geometry and conductivity receives lesser attention. Some mistakenly anticipate that in extremely low permeability formations, hydraulic fractures act as "infinitely conductive" features. However, many factors that affect the realistic conductivity of the fracture are poorly understood or overlooked. This often leads to a less than optimal outcome with wells producing below the reservoir potential.This paper presents an approach to assess the realistic fracture conductivity at in-situ conditions and the economic implications on proppant selection. The effects of transverse fractures, low areal proppant concentration and flow dynamics, are considered among other variables. The theory behind this concept is presented and supported with case studies where it has been applied in the field to various unconventional reservoirs.
Eliminating Stick-Slip by Managing Bit Depth of Cut and Minimizing Variable Torque in the Drillstring
Authors: Davis Joshua E. , Smyth Gregory F. , Bolivar Neil , Pastusek Paul E. 
Published: June 2014

Abstract
During extended reach drilling operations, stick-slip was identified within the operator’s Fast Drill Process™ workflow as the primary performance limiter in the 8-1/2-in. hole section. This dysfunction resulted in low penetration rates, frequent downhole tool failures, and bit damage. Subsequently, multiple bit runs were required to reach interval objectives.
The redesign process identified two key solutions to mitigate stick-slip vibrations. First, the bit was redesigned to limit (or manage) the depth of cut to reduce the torque variations which can excite stick-slip. Second, the torsional stiffness of the drillstring was increased by changing from 5-1/2- to 5-7/8-in. drillpipe, which reduced the magnitude of the torsional oscillations. The systematic application of these design changes allowed higher weight on bit (WOB) to be applied without stick-slip dysfunction, resulting in significantly higher penetration rates.
This paper presents the results of applying depth of cut control and drillstring design to eliminate stick-slip while drilling. Weight-on-bit, vibration, and penetration rate data will be presented over the course of eight wells. Results indicate the managed depth of cut and increased torsional stiffness provided significant reductions in vibrations leading to multiple field record rate of penetrations (ROPs), improved downhole tool life, and reduced bit damage.
Formation Damage Due to CO2 Sequestration in Deep Saline Carbonate Aquifers
Authors: Mohamed I. M. , Nasr-El-Din H. A. 
Published: June 2014

Abstract
CO2 injection in carbonate formations causes a reduction in the well injectivity, due to precipitation of the reaction products between CO2/ rock/brine. The precipitated material includes sulfate and carbonate scales. The homogeneity of the carbonate rock, in terms of mineralogy and rock structure, is an important factor that affects the behavior of permeability changes during CO2 injection.
Limestone rocks represent the homogenous rock in this study, and include: Pink Desert limestone and Austin chalk, which are mainly calcite. Silurian dolomite (composed of 98% carbonate minerals, and 2% silicate minerals) and Indiana limestone rock represent the heterogeneous rock, which have some vugs in their structure.
Coreflood experiments were conducted to compare the behavior of the permeability loss between these rocks. CO2 was injected with the water alternating gas (WAG) technique. Different brines were examined including seawater and no sulfate seawater. The experiments were run at a pressure of 1300 psi, a temperature of 200°F, and an injection rate of 5 cm3/min. A compositional simulator tool (CMG-GEM) was used to confirm the experimental results obtained in this study.
The results showed that for homogenous rocks, the presence of sodium sulfate in the injected seawater is the major factor that causes formation damage, due to calcium sulfate precipitation in CO2 environments. For dolomite rocks, higher damage was noted, due to the reactions of CO2 with the silicate minerals. For both homogenous and heterogeneous rocks, the source of damage for high permeability cores is the precipitation of reaction products, while for low permeability cores, water blockage increases the severity of formation damage. The simulation study showed that the power-law exponent, and Carman-Kozeny exponent between 5 and 6, can be used for homogenous carbonate rock to estimate the change in permeability based on the change in porosity, for heterogeneous rock a larger exponent was needed.
Improvements in Production Liner Cementing for Coiled Tubing Drilling
Authors: Johnson Mark O. , Milne John R. , Diller Carl W. 
Published: June 2014

Abstract
Since 1994 Coiled Tubing Drilling (CTD) has completed over 650 sidetracks on the North Slope of Alaska. In many aspects the window milling and drilling phase can be considered a mature technology. However, recent developments in the completion phase namely with the generation II side exhaust liner running tool (Gen II SELRT) have further increased job reliability, safety, and efficiency for the liner cementing completion phase.
This paper will begin with a brief update on the status of CTD on the North Slope (3 rigs drilling on a daily basis) and discuss how many of the challenges with drilling through/below the production tubing have been dealt with. The cost for a CTD sidetrack with an equivalent amount of reservoir exposure and zonal isolation is about one half that of a rotary sidetrack on the North Slope. This is due to efficiencies in leaving the production tubing in place (dominant savings) and less consumables. In addition, CTD’s enhanced capability for underbalanced drilling (UBD) and managed pressure drilling (MPD) make it attractive for some North Slope fields.
While the electronically controlled drilling bottomhole assembly (BHA) has improved drilling performance, the electric line (EL) inside the CT has challenged the completion phase. CT wiper darts for separating cement from displacement fluid can no longer be used. The CT wiper dart would be damaged by the EL and visa versa. Instead, the new liner running tool discussed in this paper exhausts the contaminated cement/mud interface to the annulus at top of liner before launching the liner wiper plug (LWP).
Over 76 liners have been cemented with the side exhaust technique. The last 34 jobs have been done with the Gen II SELRT that uses mechanical dogs to close the path through the LWP, side exhaust, and launch the LWP when desired. This new tool increases job efficiency over the first generation tool and continues to provide reliable liner cementing with EL in the coil.
Use of Liner Drilling Technology as a Mitigation to Loss Intervals and Hole Instability: A Case Study in Mississippi Canyon
Authors: Rosenberg Steven M. , Gala Deepak M. 
Published: June 2014

Abstract
Liner drilling technology provided an effective solution to hole instability issues seen while drilling with conventional methods through a narrow mud weight/pore pressure/fracture gradient window laden with depleted intervals and virgin pressured shales in the Mississippi Canyon block of the Gulf of Mexico.
Two 8-1/2" x 9-1/2" wellbores were lost while drilling with Rotary Steerable Systems (RSS) in the 60° wellbore. The initial wellbore was lost as a result of RSS failure resulting in the hole packing off. A subsequent bypass wellbore encountered catastrophic lost circulation resulting in the hole collapsing as the depleted commercial sand came in unexpectedly high. In each case this resulted in the loss of the RSS Bottomhole Assembly (BHA).
Liner drilling technology was identified as the most appropriate strategy for setting the 7-5/8" drilling liner and 5-1/2" production liner because:
Documented lost circulation problems have been minimized or eliminated through prior use of DwL technology, largely attributed to the "smear effect" phenomenon. The narrow annular geometry created by liner drilling reduces the rate of fluid loss in the annulus as compared to conventional drilling operations enabling effective management of the annular fluid level. DwL systems historically minimize or eliminate non-productive time in operations in which uncontrolled fluid losses have been encountered previously.
Ultimately, the correct application of liner drilling technology on this well allowed the operator to reach the intended drilling depth and completion objective. The equipment selection, operation, and results of the liner drilling operations will be presented in the paper.
Interventionless Surveillance in a Multi-Lateral Horizontal Well
Authors: Andresen Christian , Williams Brock , Morgan Mike , Williams Theresa , Crumrine Tim , Bond Andy , Franks James 
Published: June 2014

Abstract
Reservoir developments that rely on long horizontal wells are common practice. Understanding the inflow distribution from a horizontal well is an ongoing challenge for our industry. The effectiveness of reservoir management decisions are greatly improved with an understanding of the flow distribution across the reservoir interval.
While technologies have been developed using tractors or coiled tubing to deploy production logging tools into horizontal wells, it requires a well intervention operation, increases risk exposure and is not always successful.
This paper reviews a case study from a multi-lateral well in Alaska where a new style of chemical tracers embedded into the completion equipment was used to derive a quantitative estimate of the inflow distribution in a dual horizontal, multi-lateral well.
The chemical tracers, which resemble strips of plastic, are designed to release unique chemical fingerprints when contacted by oil. The tracers are then detected in the oil to concentrations as low as 1 part per trillion. In this case study six locations were selected for placement of oil sensitive tracers.
During a shut-in period the strips continue to release their unique chemical tracers causing an increased tracer concentration to develop in the oil immediately surrounding the tracer location. Upon start up, these small volumes of oil, containing the higher concentration of tracer, are displaced to the surface. Samples of the produced oil are analyzed to develop a plot of each tracer’s concentration vs produced volume. The arrival of the oil containing the high tracer concentration is related to the inflow distribution.
This paper reviews results from a field deployment in a dual lateral well that contained 3 tracer locations in each lateral. The results from this well indicate that one lateral was producing approximately 30% more than the other lateral. Additionally the data indicates the toe of one of the laterals was a major contributor to the total well flow.
This insight into the reservoir performance was obtained with no intervention into the well and only minor modifications to the completion design.
Contractual Language Needed to Help Reduce Integrated Control Systems Risk on High-Specification Assets
Authors: O’Grady Bill 
Published: June 2014

Abstract
Control systems software is a mission-critical component of the drilling control, dynamic positioning, power, subsea, and vessel management systems on high-specification offshore assets. The unique features of this mission-critical software cannot be adequately addressed using the same contractual language that provides Performance, Quality, Health, Safety, and Environmental (PQHSE) assurances for hardware systems; software-specific language is also needed.
Unfortunately, most contracts in the oil and gas industry do not articulate software-specific PQHSE expectations. This often results in non-productive time (NPT) and health, safety and environmental (HSE) risks during operations. Effective contractual software standards:
Are based on an internationally recognized body of standards and guidance Establish expectations for measuring ongoing control systems software PQHSE levels through inspection, auditing, and testing Encourage vendor-stakeholder collaboration and shared accountability Enable control systems software to be continually improved
This paper will help Drilling Contractors, Operators and Shipyards develop and leverage contractual software standards to create an environment in which:
Vendors and stakeholders can work together to improve systems quality onboard high-specification assets All parties involved in asset construction and operation are appropriately accountable for helping to ensure that software-related issues do not result in NPT or HSE risk
The Effects of Back Rake and Side Rake Angles on Mechanical Specific Energy of Single PDC Cutters with Selected Rocks at Varying Depth of Cuts and Confining Pressures
Authors: Rajabov Vusal , Miska Stefan , Mortimer Laurence , Yu Mengjiao , Ozbayoglu Evren 
Published: June 2014

Abstract
One of the key objectives within the drilling industry is optimizing rate of penetration (ROP) and a major contributor to obtaining this objective is the PDC bit design. Whilst previous papers have proven that the PDC cutting structure geometry, particularly back rake and side rake angles, affect PDC bit performance when tested at atmospheric conditions, no information in the SPE literature exists for similar tests at confining pressures. The effect of side rake angle on cutter aggresiveness and cutter interaction at depths of cut (DOC) in excess of 0.04” are particularly unknown under confined pressure.
The results of more than 150 tests show that back rake and side rake angles have substantial effects on Mechanical Specific Energy (MSE) and the aggressiveness of PDC cutters. Experiments with three different rock types; Carthage marble, Mancos shale, and Torrey Buff sandstone, revealed that at both atmospheric and elevated confining pressures, PDC cutters with 10 deg back rake angles require half the energy to cut the same volume of rock and produce higher cutting efficiency compared with cutters having 40 deg back rake angles. Possible reasons for this behavior are explained through the analysis of the cutting process.
Results show that a cutter with low back rake requires less horizontal cutting force in order to cut the same volume of rock. This observation indicates that not only will a PDC bit with lower back rake angles, drill more efficiently, but it will also require less torque in order to drill at the same ROP. Other factors such as reduced durability of cutters at low back rake angles should also be considered while applying these results to PDC bit designs.
Test results at both atmospheric and confining pressures revealed that MSE decreases with increasing DOC up to 0.08” on all three rock types. However, the tests also showed that MSE starts to increase slightly at DOCs above 0.08”, possibly suggesting an optimal minimum DOC.
Experimental results also show that, whilst Mancos shale and Carthage marble have about the same compressive strength, Mancos shale requires three times less energy to cut compared to Carthage marble. This indicates that, compressive strength of some rocks such as shales cannot be used alone as a reference rock property for accurately evaluating and comparing drilling efficiency.
A new 3D mechanistic PDC cutter-rock interaction model was also developed which incorporates the effects of both back rake and side rake angles, along with rock specific coefficient of friction. The results from this single-cutter model are encouraging as they are consistent with the experimental data.
Rheological Properties of Invert Emulsion Drilling Fluid under Extreme HPHT Conditions
Authors: Lee John , Shadravan Arash , Young Steve 
Published: June 2014

Abstract
Limited amount of rheological data generated under extreme high-pressure, high-temperature, (HPHT) conditions (&gt;500°F/30,000 psi) have been published due to lack of suitable viscometer and drilling fluid for such conditions. This paper compares the rheological properties of invert emulsion drilling fluid generated from four types of HPHT viscometers and provides a simple rheological model that can be used to predict the behavior of OBM under extreme-HPHT conditions.
Previously most of the HPHT studies were limited to 20,000 psi and 500°F. Recently more than one extreme-HPHT rheometers have become commercially available, which can measure the rheological properties of drilling fluids at conditions up to 600°F and 40,000 psi. These viscometers have been used to test various invert emulsion drilling fluid samples to the maximum capacity of the equipment. Parts of the data generated from one particular instrument have been compared with data obtained from other rheometers that are operated at lower temperature and pressure.
The data indicated several factors can critically affect the rheology measurements, including drilling fluid chemistry, instrument set up and test schedule. Rheological properties measured by various instruments differed slightly from each other perhaps due to design differences. Temperature and pressure not only affect the rheological properties of the test fluid but may also impact the performance of the critical mechanical parts used for rheology measurement. In addition, HSE experience gained from working with extreme-HPHT instruments is also included in this paper.
Improving Casing Wear Prediction and Mitigation Using a Statistically Based Model
Authors: Mitchell Sarah , Xiang Yanghua 
Published: June 2014

Abstract
Wells are now routinely drilled both in deepwater and on land to depths that were previously considered impossible. In these environments, casing design is critical to safely and successfully drilling and producing wells, and unexpected casing wear can result in significant costs or even the loss of a well. As part of a successful casing design strategy, the engineer must assess the maximum permissible casing wear required to maintain casing integrity. Then, steps must be taken to ensure that casing wear thresholds are not exceeded.
Casing wear models use the number of drill string revolutions and contact force between the drill pipe and casing to calculate wear. The contact force is calculated using the dog-leg severity within the well, with the maximum dog-leg severity often determining the location and extent of the most severe casing wear. There is often a large discrepancy between predicted and actual casing wear because of survey quality and inaccurate estimates of dog-leg severity and total revolutions. These discrepancies result in predictions of contact force and drill string revolutions that are in error by 50% or more. To improve the accuracy of casing wear models, an extensive database was created from a wide variety of wells with measured depths greater than 13,000ft. The database results in a statistically based model for determining dog-leg severity within vertical, build, and tangent sections, as well as total drill string revolutions at various levels of confidence to bound average and maximum expected contact force and casing wear.
Case histories compare measured wear with predictions of casing wear based on original well data and the statistically based model. The case histories also demonstrate the effect of various drilling parameters on casing wear, and evaluate the effectiveness of non-rotating protectors in preventing casing wear.
Real-Time Motor and Turbine Performance Monitoring and Optimization
Authors: Ringer M. , Johnson A. , Barrett M. , Goldsmith G. , Flint G. , Mao S. , Terracina D. 
Published: June 2014

Abstract
We present the results from a field test in which both a drilling turbine and a positive displacement motor were instrumented to provide real-time measurement of their shaft speed. This permitted the construction, in real-time, of the actual performance characteristics of the motor, and immediate feedback as to the driller’s operating point on the motor’s power curve. By determining the actual performance curves of the motor in real-time, we were then able to operate the motor at a desired point on its power curve and significantly increase ROP without inducing a single motor stall.
The test also highlighted potential differences between the published and the actual downhole performance curves of the motors, as well as the ability to track changes in the motor’s performance over time.