bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Concentric 4×1 Design for Multi-Path Gravel Pack System Extends Effective Packable Length and Eliminates Additional Make-up Time
Authors: Fisher B. , Nguyen H. , Snitkoff J. 
Published: October 2014

Abstract
A common problem for modern horizontal gravel pack operations is the development of an annular bridge that blocks the flow of gravel slurry and prevents formation of a complete pack. Causes of annular bridging include high-rate leakoff zones or swelling shale layers within the reservoir. Secondary flow path technologies enable slurry flow to bypass any annular bridge and complete the packing of an openhole annulus. Current secondary flow path technologies on the market either lack the flow configuration to extend farther than several hundred feet, or they add complicated makeup and running procedures to align and secure a secondary slurry flow path.
A tube configuration has recently been developed to add redundancy to the flow path geometry as well as greatly increase the overall flow area, extending the effective packable length of the system. The 4×1 concentric tube design has been combined with an integral internal cross-coupling communication system, connecting tubes at each joint and adding no additional makeup time to the running procedure of conventional sand screens.
This paper presents the results of full-scale gravel pack simulations with leakoff and an annular barrier. The prototype multi-path system was run horizontally inside a simulated 8½-in. open hole. Slurry flow, prepared using conventional proppant in a viscous carrier gel or with ultra-low density proppant, successfully bypassed the sand dune created by the leakoff zone and the solid annular barrier, reaching all void areas and creating a complete pack.
By enabling slurry flow to bypass any annular bridge and reliably complete the packing of longer and longer horizontal intervals, secondary flow path technology promises to provide a reliable, low-cost solution for delivering failure-free gravel pack completions. Emerging technology in this field strives to simplify running procedure, extend functional length of secondary flow paths and reduce relative packing time.
Integrated Analysis for Fracture Identification During Hydraulic Fracturing
Authors: Guest A. , Rebel E. , Bailly S. , Kostadinovic J. 
Published: October 2014

Abstract
In order to improve our understanding of the interaction of the hydraulic fracture with pre-existing structures in reservoirs, we focused on separating microseismicity related to the hydraulic fracture propagation and microseismicity occurring along the pre-existing structures. We analyzed microseismic activity detected during the stimulation job in a horizontal well with ten stages. The microseismicity aligns in two major trends, E-W and NE-SW. The microseismicity in the NE-SW trend is aligned with the maximum horizontal stress and is related to the hydraulic fracture propagation. The E-W trend is related to the interaction of the hydraulic fracture with the pre-existing structures in the area. Some stimulated stages show very clear and distinguished spatial separation of microseismicity related to the two trends while some stages have more complex pattern. We combine several techniques that help to distinguish various types of seismicity: data set separation, geomechanical, magnitude-frequency, and well pressure analyses. The synthesis of the various methods helps to improve our understanding of the well stimulation. Overall, we almost doubled the number of hydrofractures and fault/fracture zones in comparison to the original interpretation based only on the microseismic mapping and we better constrained the half-lengths of the hydraulic fractures. The detailed data analysis strongly suggests that some hydraulic fractures may be aseismic.
Completion Optimization with Ceramics Provides Step Changes in Horizontal Performance for the 2nd Bone Spring Formation – A Southeastern New Mexico Case History
Authors: Jackson Kale , Palisch Terry , Lehman Lyle 
Published: October 2014

Abstract
The Permian Basin is one of the longest producing oil basins in the United States. To the west the Delaware Basin, located in southeastern New Mexico (SE NM) and West Texas, once thought to be extinct, has been revived through horizontal drilling and completion technologies. These tight formations, more importantly the Bone Spring formation, that were once uneconomic through vertical completions, have seen dramatic production and economic improvements with the advancement of horizontal drilling and completion technology lending to different requirements for proppant and fluid rheology for hydraulic fracturing optimization.
The Bone Spring formation in SE NM is a thick sequence of interbedded sandstones, carbonates, and shales with depths ranging from 6,000′ – 13,000′ that gradually deepens toward the southern part of the Delaware Basin. The discovery of an oil rich 1st, 2nd, and 3rd Bone Spring formation amid a much more gas-prone Avalon and Wolfcamp clearly demonstrates the complexity of the Delaware Basin, and does not adhere to either conventional or unconventional expectations of hydrocarbon development.
Due to this complexity, the following paper will describe the reservoir and completion concerns that have arisen from the deeper 2nd Bone Spring formation located in Lea County, NM and how adapting current industry completion techniques have proven to enhance the overall development. Topics that will be discussed in this paper include: Landing interval/lateral target pointStage spacing/perf clusters/perf strategyHydraulic fracture treatment design optimizationThe benefits of employing ceramic proppantIncreased productivity and EUR of 30%Production choke management and proppant flowbackCase history overview based on two re-entry horizontals and nine new-drill laterals
Horizontal drilling along with hydraulic fracturing have become the keys to unlocking potential reserves within the various Bone Spring formations. The successful methodologies and results presented in this paper will spur thought and discussion among engineers and the general SPE community, thereby discouraging simple repetitive designs and encouraging progressive thinking within this complex formation. The methodologies presented in this paper can also be applied to other liquids-rich resource plays that engineers will hopefully employ.
Trapped Gas Saturation Measurements: New Perspectives
Authors: Bona N. , Garofoli L. , Radaelli F. , Zanaboni C. , Bendotti A. , Mezzapesa D. 
Published: October 2014

Abstract
When a gas reservoir is overlying an aquifer, water will imbibe into the gas-saturated zone with the onset of gas production, trapping a certain amount of gas. This mechanism is expected to occur in a super giant field in Mozambique that hosts over 80 TCF of natural gas in place. The observed laboratory variations in trapped gas saturation represent one of the main uncertainties in the recoverable reserves of the field. Two laboratory methods for estimating this quantity are compared: one is the classic test in which core samples are immersed in a liquid and undergo a spontaneous imbibition measurement. The other is a new method that involves a series of forced imbibitions and combines centrifuge and NMR measurements. While the standard method produces countercurrent imbibition data, the new method generates co-current results. These are more representative of the reservoir process and tend to be more optimistic. The data analysis process involves the estimation of two critical Bond numbers: one is the classic value for the mobilization of trapped blobs of residual gas, the other sets the boundary between countercurrent and co-current imbibition regimes. Representative trapped gas saturation results are obtained only for Bond numbers lying between the two critical values. The new method is validated by the log data acquired in the two reservoirs under examination below the gas water contact, where immobile gas saturations are observed. Being caused by the rise of a paleo-contact, the observed saturations are considered to be representative of the trapped saturations that will form in the reservoir when production starts and taken as a reference for the lab measurements.
A Semi-Analytical Forecasting Method for Unconventional Gas and Light Oil Wells: A Hybrid Approach for Addressing the Limitations of Existing Empirical and Analytical Methods
Authors: Clarkson C. R. , Qanbari F. 
Published: October 2014

Abstract
The rapid pace of exploitation of unconventional gas and light oil (UG/ULO) plays in North America has necessitated the development of new production forecasting methodologies to aid in reserves assessment, capital planning and field optimization. The generation of defendable forecasts is challenged not only by reservoir complexities but also by the use of multi-fractured horizontal wells (MFHWs) for development.
In this work, we have developed a semi-analytical method that provides a solid theoretical basis for forecasting. The technique is analytical in that it uses the methods of Agarwal (2010) to calculate contacted oil- and gas-in-place (COIP/CGIP) from production rates, flowing pressures and fluid properties. The rate-normalized pressure (for liquids) or pseudopressure (for gas) derivative (RNP') is a key component of the calculation. The technique is also empirical in that an empirical function is fit to the resulting COIP/CGIP curve versus time. Although the method is flexible enough that any equation can be used to represent the COIP/CGIP curve, and hence the sequence of flow-regimes exhibited by MFHWs, the equation must be capable of being integrated to allow extraction of rate-normalized pressure or pseudopressure (RNP). The stabilized COIP/OGIP during boundary-dominated flow must be specified for forecasting – thereafter, the method uses a material balance simulator to model boundary-dominated flow. Hence, if the well is still in transient flow, a range in forecasts may be generated, depending on the assumed stabilized COIP/OGIP.
Our new semi-analytical method addresses some of the current limitations of empirical and fully analytical (modeling) approaches. Empirical methods, which have been adapted to account for long transient and transitional flow periods associated with ultra-low permeability reservoirs, lack a theoretical basis, and therefore input parameters may be difficult to constrain. However, empirical methods are simple to apply and require a minimum amount of data for forecasting. Analytical models, while better representing the physics, nonetheless require additional reservoir and hydraulic fracture data which may not be available on every well in the field. The semi-analytical method proposed herein is intended to bridge the gap between empirical and modeling-based approaches – it is more rigorous than purely empirical methods, while requiring less data than fully analytical techniques.
The new method is tested against simulated and field cases (tight oil and shale gas). Although we have used a simple power-law function to represent COIP/OGIP curve, which appears adequate for the cases studied, we note that wells exhibiting long transitional (e.g. elliptical/radial) will likely require a different functional form.
Field Premiere of Along-String Dynamic Measurements for Automated Drilling Optimization Using Downhole Information
Authors: Veeningen Daan , Pink Tony , McRay Mike , Luthi Melanie 
Published: October 2014

Abstract
The question of what is happening downhole is routinely answered through human interpretation of surface data. While widely available, subsurface data is typically pulsed from near the bit and acquired at low frequencies, resulting in considerable latency issues. Consequently, the majority of acquired subsurface data is memory-stored in drilling tools for post-well analysis, which, while useful for drilling subsequent wells in similar environments, does not allow for early detection and mitigation of unexpected downhole events.
This paper details field deployments of a system that offers real-time downhole measurements from the bottomhole assembly (BHA) and from two additional positions along the string. The system aids wellsite personnel and yields consistent performance through the use of automated closed-loop surface machinery control based on these real-time downhole measurements through an 80Hz downhole data-stream.
The high-frequency data acquisition system provides sufficient sampling resolution to diagnose many drilling dysfunctions in real time, including damaging events such as severe torsional oscillations leading to stick/slip, bit-bounce and whirl-induced vibrations. This allows mitigation strategies to be quickly evaluated and implemented based on adequacy and performance, preventing damage and improving performance. In addition, high-frequency toolface and survey data promoted directional drilling and sliding-drilling efficiency in the build and horizontal lateral.
This field test marks the premiere of along-string dynamic measurements above and beyond the pressure and temperature measurements that were already available to identify, analyze and control events along the wellbore. These include detecting tri-axial vibrations and rotation in real time, allowing drilling phenomena to be identified and quantified while also highlighting the dynamic variability of drillstring rotation and motion. In addition, the system improves the efficiency of hole cleaning and, through equivalent circulating density (ECD), evaluation along the string.
The system provides clarity regarding what is happening subsurface and offers automated rig control based on high-resolution downhole information from along the drillstring. Recommendations are offered, providing useful techniques for automation and drilling optimization projects.
Confidence in Critical Velocity Predictions for Solids Transport
Authors: Soepyan F. B. , Cremaschi S. , Sarica C. , Subramani H. J. , Kouba G. E. , Gao H. 
Published: October 2014

Abstract
Sand is often produced with oil and gas even though sand control practices are used. To successfully transport solids in pipelines, the fluid velocity must exceed the critical velocity. Solids transport models are used to predict this velocity. However, for the same input field or laboratory condition, the models' critical velocity predictions may differ by orders of magnitude. Furthermore, none of the models provide information regarding the confidence in their velocity predictions. This paper introduces a systematic methodology, which selects the appropriate solids transport models for predicting the operational critical velocity envelope to ensure solids transport in the pipe to within a predetermined confidence level. Given a field or laboratory condition as input, the approach generates: (1) velocity predictions and uncertainty bounds of all models to within a predetermined confidence level, (2) recommendation of appropriate models for calculating the critical velocity at the input condition, and (3) impact of the uncertainty of input condition, experimental data, and model on the overall uncertainty bounds. The methodology uses data clustering, model evaluation, optimization, and uncertainty propagation approaches. Based on three Case Studies, the velocity envelopes suggested by the methodology, at the 90% confidence level, are consistent with experimental observations. For input laboratory conditions, which are used for validation purposes, the contributions of model, input condition, and experimental data uncertainties to the velocity prediction uncertainty were between 50 – 90%, 3 – 20%, and 6 – 40%, respectively. If the parameters of the selected models were fine-tuned, for the same input conditions, the above uncertainties contribute about 40 – 90%, 4 – 15%, and 1 – 50%, respectively, to the velocity prediction uncertainty. For an input field condition (the fourth Case Study), the above values become about 35 – 70%, 7 – 25%, and 25 – 45%, respectively; and about 25 – 30%, 30 – 32%, and 40 – 42%, respectively, if the parameters of the models are fine-tuned prior to uncertainty estimation. The results of these Case Studies suggest that for laboratory conditions, most of the uncertainty in a model's critical velocity prediction comes from the model, while for field conditions, the uncertainties of the model, input condition, and data may have nearly equal contributions.
Multilateral Level-5 Dual Long Horizontal Openhole Gravel Pack Completion on the Peregrino Field
Authors: Ranjeva Jean-Michel , Dahl Espen , Martinho Flavio , Gonçalves Bruno , Ramos Astrid 
Published: October 2014

Abstract
Peregrino is an offshore oil field (block BM-C-7) located east of Rio de Janeiro, Brazil in the southwest part of the Campos Basin area. The oil field was discovered in 2004. Statoil Oil and Gas, Brazil has been operating the Peregrino Feld since 2008. The unconsolidated reservoir (Carapebus formation) shows a mid to high permeability and produces heavy oil.
The lower completion design requirements called for a screened completion with long openhole horizontal gravel packs for sand control and production optimization throughout the life of the field. Horizontal openhole lengths ranged from 800 m to 2,300 m for Peregrino producers. To date, 28 producer wells have been drilled and completed with horizontal gravelpacks. Since wells are not free flowing, artificial lift is required, and electric submersible pumps (ESPs) were chosen to perform the artificial lift; therefore, the upper completion architecture was designed with workover capabilities so that the pumps could be changed out as needed.
In order to maximize reservoir drainage, to save the platform's slot availability, and to optimize ESP efficiency, Statoil planned to drill and complete dual horizontal multilateral wells with horizontal gravel packs on each branch that would have the capability for selective production from each lateral section.For Well B05Y1/Y2, both branches were completed with two open holes of 1300 meters and 800 meters, respectively. These were fully gravel packed and had a Level 5 Junction installed.
This paper will describe:
The target zones The gravel-packing challenges The completion base of design The installation sequences The liner-conveyed gravel-pack technique used to gravel pack the lateral bore The TAML level 5 MLT installation The lessons learned.
The successful installation of a dual-bore horizontal gravel-pack completion with a Level 5 Multilateral System offshore was an industry first for Brazil that opened ambitious perspectives for the Peregrino field in terms of increased reservoir drainage that would improve the oil-recovery factor, and thus, the economic gains. This first multilateral well in offshore Brazil is part of the operator's increased oil recovery (IOR) efforts for the Peregrino field. This is also the first multilateral well in Brazil with gravel packs in both branches.
Successful Campaign Using Coiled Tubing to Perforate Five HPHT Wells in the UK Central North Sea
Authors: Taggart Michael , Phan Truong , Murray Lewis , Cassidy Mike 
Published: October 2014

Abstract
This paper details the planning, design and execution of a successful campaign to perforate five HPHT wells, using Coiled Tubing (CT), in the UK Central North Sea. The project goal was to perforate extended intervals, in live well conditions, in one run and leaving no guns or restrictions downhole.
The well conditions presented challenges to the design and operation of CT in this campaign. Challenging factors included:
The use of high yield strength CT (130,000ksi grade material). Wellhead pressure up to 9,000 psi. Bottomhole pressure up to 12,500 psi. Estimated BHT 375° F. Estimated FWHT 320° F. Well depths of 21,000 ft MDRKB. Deployment of up to 1,645 ft of 2 7/8″ perforating guns. Perforating gun string retrieval to surface. No rathole to drop guns due to: Penetration of the reservoir water bearing zone, potentially leading to produced water and scaling issues in later well life. Access required across the formation for data acquisition and reperforation operations. Cost and time involved drilling hard HPHT formations.
Job design was critical to the success of the operation and consideration given to learnings from similar previous operation. This included selection and analysis of CT material, size, wall thickness and managing potential CT collapse pressure following reservoir perforation.
Further analysis, included calculation of CT stretch, circulation pressure, and wellbore solids removal studies.
Reverse circulation through the CT was carried out. This would increase the effectiveness of fluid displacement when creating an underbalance situation prior to perforation. In order to maintain pressure barriers specific tooling was required to minimise the risk during this operation.
The completion design is discussed with specific attention to the process of eliminating the requirement to deploy and recover perforating guns whilst maintaining control of the surface pressure. The ability to maintain a dual pressure barrier within the completion saved considerable time over the conventional method of recovering long gun strings with pressure at the wellhead.
An important element contribution to the success of the operation was the completion of additional equipment tests completed prior to the commencement of operations. The testing demonstrated equipment was fit for purpose and established critical interfaces as well as creating synergies with the multi-vendor delivery team. The fine-tuned operational and procedural aspects of the job and led to several modifications to equipment and procedures. Further testing was completed to confirm functionality the data acquisition, allowing monitoring and recording of pressures, circulation rate and depth control.
The job design, planning, qualification of equipment and the use of dedicated competent personnel lead to the successful perforation campaign of five HPHT wells without any accidents, environmental spills or lost time and within budget.