bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Modified Design for Gravel Packing with Expandable Rubber Beads
Authors: Ramezanian Mahdi , Emadi Hossein , Wang Hong 
Published: April 2019

Abstract
In oil and gas wells with sand control completion, during gravel pack installation and production life of the well, void spots - known as hotspots - may form in gravel packs. Hotspots provide permeable channels within the pack that allow sand to pass into the wellbore and consequently loosen the pack. Finding an innovative way to prevent hotspots from forming maintains the gravel pack integrity and preserves its efficiency. Indeed, this approach would save money by reducing the demand for remedial operations. This paper introduces, a modified design for gravel packing with expandable rubber beads. The new pack is composed of gravel and expandable rubber beads rather than 100% gravel and is capable of avoiding the hotspots and maintaining pack tightness. A series of experiments were conducted, with diesel, on 100% expandable rubber bead packs and mixtures of gravel and bead to measure their swelling capacity and permeability. The swelling volume was evaluated to assess the beads capacity to fill the hotspots and permeability was measured to assess their potential to create flow barrier. The tests show promising permeabilities for gravel/rubber bead packs and reasonable expansion potential to fill the hotspots. Increasing the proportion of the beads in gravel/rubber bead mixture pack, results in very low permeability. Hence, finding an optimum proportion of rubber beads is essential to designing a pack that will take advantage of their swelling capacity to avoid hotspots while retaining reasonable permeability toward the flow.
Impact of Frac Hits on Production Performance- A Case Study in Marcellus Shale
Authors: Khodabakhshnejad Arman 
Published: April 2019

Abstract
A new approach is proposed to quantify the communication between wells in a tight multi-layered shale gas reservoir. In this approach, a wide range of data sets, from microseismic monitoring to the production data are analyzed to evaluate the communication between wells in every stage of well development. The results provide new insight into how the initial well communication during stimulation impacts the well interference during production.
Microseismic data collected during hydraulic fracturing are analyzed for a three-well pad drilled in the Appalachian basin. The microseismic event locations, magnitudes, and fracture plane characteristics are used to construct a discrete fracture network (DFN). The permeability of a numerical reservoir model is calculated from the generated DFN, and the model is further integrated with available reservoir data. History matching is carried out using three years of production data to calibrate the reservoir model, which was also used to predict water and gas production for thirty years. Finally, decline curve analysis (DCA) is used to examine the production behavior of the reservoir.
The microseismic data monitored during hydraulic fracturing show the presence of communication between wells in the pad. This communication, also known as frac hits, is established as more events are recorded in the offset wells, indicating the extent of hydraulic fractures. In addition, the pressure perturbation in the offset wells confirms the presence of a pathway connecting the wells during stimulation. Furthermore, the reservoir model built in the numerical reservoir simulator shows overlap of drainage volumes. In the reservoir model, the depleted region expands across multilayer formations in both lateral and vertical directions. An analysis of the production behavior of the wells using DCA suggests an almost logarithmic trend which is expected for these types of reservoirs. Surprisingly, detailed analysis of the results reveals there is no significant deviation in the overall performance of wells associated with well interference, especially in the early years of production. However, at greater than 10 years of production, the expansion of the depleted zone accelerates the well interference which leads to lower performance of the pad in the long term. The results demonstrate that the enhanced permeability zones created due to frac hits may not have an immediate impact on production performance.
Traditionally, frac hits and well communication were considered damaging to the reservoir production. However, this new result shows that the well communication during fracturing may not impact short-term production. Additionally, it highlights the importance of a thorough examination of the fracture network along with the reservoir properties to evaluate the potential impact of frac hits on reservoir production.
A Prediction Method for Estimating Time to Convert From Cyclic to Drive in Steam Injection Processes
Authors: Ssembatya Henry , Ershaghi Iraj 
Published: April 2019

Abstract
There is significant history on the use of steam injection processes in California heavy oil reservoirs. In this paper, we introduce a graphical method for estimating the optimal timing of conversion from Cyclic Steam Stimulation (CSS) to steam drive and compare our estimation to actual cases where CSS had continued with the buildup of significant water saturation around the wellbore. We use as a measure, the SOR (Steam Oil Ratio) to ascertain the optimality of the conversion points and compare it to our modeling work. During the CSS process, steam injectivity is gradually improved, resulting in low SOR which is the characteristic of the steam stimulation process. We see of course some relation between the behaviors of various oil viscosity types and the SOR during CSS. But in general, the rapid heating of the formation relates to limitations associated with contact volume. Based on our numerical modeling, we demonstrate that a log-log plot of cumulative injection vs. cumulative production for all the cycles leads to a linear relationship. When there is an indication of flattening of oil steam ratio or an increase in SOR, it is time to change to steam drive allowing the steam to contact a larger volume of the reservoir. Thus, the heat-scavenging effects of water buildup around the injection well and low relative permeabilities of oil traveling through the high water saturation interval are avoided. The estimated SOR during the CSS process depends on the oil viscosities and vertical conformance. The optimum time corresponds to the point where there is deterioration of the SOR. We showcase studies on several CSS wells from fields in Central California validating the graphical method and demonstrating the steam savings had the proposed timing been implemented. The methodology presented confirms a practical and smart way for operators to decide on the conversion timing.
Synergistic Effect between Surfactant and Nanoparticles on the Stability of Methane Foam in EOR Processes
Authors: Qian Chen , Telmadarreie Ali , Dong Mingzhe , Bryant Steven 
Published: April 2019

Abstract
The major challenge in enhanced oil recovery (EOR) by gas injection is poor volumetric sweep efficiency, mainly due to the high gas mobility and reservoir heterogeneity. Injecting gas as a foam increases sweep efficiency, but maintaining foam stability within the reservoir remains a challenge. This research evaluates the synergistic interaction of one type of nanoparticle and a surfactant to increase foam stability, using the concentration ratio of the two components to tune the affinity of the nanoparticle for the gas/liquid interface. We test the capability of the synergistic two-component system to stabilize methane foam and compare it with foam stabilized by surfactants only. A key distinction is the foam stability upon contact with oil, and we explain the observations in static and dynamic conditions.
Foam stability was measured both in static (foam height) and dynamic (flow through porous media) conditions. In the static test, foam is generated by the shaking method, and foam texture (bubble size and shape) and the decay of foam height with time are indicators of foam stability. To test static stability in presence of oil, heavy oil is injected into the foam-liquid interface. In dynamic test, foam is pre-generated before flowing at elevated pressures into sandpacks containing various oil saturations. Normalized pressure gradient, and apparent viscosity are the indicators of foam stability and effectiveness for improving oil recovery.
The extent to which nanoparticles are covered with surfactant governs the foam stability both in static and dynamic conditions. Static foam is stable in the presence of oil only if the nanoparticles are partially covered by the surfactant. In the dynamic test, foam stabilized with the only surfactant collapses in the porous media when oil is present. Nanoparticles alone could not generate foam regardless of the presence of oil, but foam stabilized with nanoparticles partially covered by surfactant is stable in the presence of both residual and initial oil. In both static and dynamic conditions, nanoparticles completely covered with a bilayer of surfactant do not stabilize foam in the presence of oil. Partially covered nanoparticles foam also demonstrated salt tolerance in both static and dynamic test. Thus at appropriate surface coverage, the combination of nanoparticles and surfactant is more effective than either stabilizer alone.
The result shows that surfactant and nanoparticles interaction is important in foam stability in the porous media with oil. In particular, this interaction is synergistic at certain coverage. This type of synergy can provide much more robust mobility control for EOR processes involving gas injection.
Further Investigation of Downhole Heating by an Electric Cable
Authors: Medizade Mason M. , Wiltshire Zach 
Published: April 2019

Abstract
Heat is an important component in heavy oil production. One method includes generation of electric current using solar panels or other methods and converting electricity into heat for surface or downhole applications via an electric cable. The heat can help removal of paraffin, wax or hydrate in the production tubing, removal of heat sensitive skins in and around perforations and reduction of oil viscosity in the reservoir zone. The objectives of this study are to present the results obtained from a finite element model study including the cable, well, and the reservoir. Reported results are in continuation of our previous study reported in SPE-185736-MS in 2017. The study uses a commercial finite element model. The model consists of the production tubing, cable, well and the porous media as the reservoir zone. The wellbore fluid is different gases or mostly water. The cable is attached to the production tubing's sides and immersed in well fluid in different lengths. The model solves the two-dimensional heat of conduction equation providing same temperature distributions obtained from other analytical methods. Following parameters are changed using a fixed cable heat density, W/m: well fluids, length of cable immersed, cable orientation, cable lengths, reservoir thermal conductivity and reservoir porosity. The finite element model runs are obtained for vertical well at different model mesh sizes. The best results were reported. In case of stagnant gas surrounding the electric cable, the sand face of the well heats up very quickly. However, transfer of heat up to many meters into the reservoir continues at a slower pace. Similar results are obtained for both vertical as well as horizontal wells. Thermal conductivity of the porous media and its specific heat and density plays an important role in heat transfer and distribution in the reservoir zone. If water is surrounding the cable and given its thermodynamic states of pressure and temperature is allowed to reach near boiling, the heat transfer to the reservoir naturally can be accelerated due to initiation of latent heat of vaporization and its transfer to the reservoir. This study will present all the new finite element runs obtained and the temperature distributions as a function of time and radial distances into the reservoir. Heat is always needed in production of heavy oils worldwide and specifically in California as steam injection faces its own operational challenges. The technology of electric heating needs to be understood and cables needed to be designed properly and effectively. If that happens many deeper and larger heavy oil zones can be produced more economically. Like other similar studies, this study will help design evolution needed for more rugged and robust and effective downhole heaters.
Evaluation of Gas and Downhole Water Sink-Assisted Gravity Drainage GDWS-AGD Process in Saturated Oil Reservoirs with Infinite-Acting Aquifer
Authors: Al-Obaidi Dahlia A , Al-Mudhafar Watheq J , Wojtanowicz Andrew K , Al-Jawad Mohammed S , Saini Dayanand 
Published: April 2019

Abstract
A hybrid Gas-Enhanced and Downhole Water Sink-Assisted Gravity Drainage (GDWS-AGD) process has been suggested to enhance oil recovery by placing vertical injectors for CO2 at the top of the reservoir with a series of horizontal oil-producing and water-drainage wells located above and below the oil-water contact, respectively. The injected gas builds a gas cap that drives the oil to the (upper) oil-producing wells while the bottom water-drainage wells control water cresting. The hybrid process of GDWS-AGD process has been first developed and tested in vertical wells to minimize water cut in reservoirs with bottom water drive and strong water coning tendencies. The wells were dual-completed with 7-inch production casing and 2-3/8 inch tubings and perforated above the oil-water contact (OWC) for oil production and below OWC for water drainage. The two completions were hydraulically isolated inside the well by a packer. The bottom (water sink) completion drained water with a submersible pump.
The GDWS-AGD was efficiently adopted to improve oil recovery at the PUNQ saturated oil field. The PUNQ Field has an infinite active aquifer with very strong edge and bottom water drives. A black oil reservoir flow model was implemented for CO2 flooding simulation of the GDWS-AGD process in comparison with the Gas-Assisted Gravity Drainage (GAGD) process. The comparison was performed to obtain the clearest image about the performance of the combined GDWS-AGD process. Next, Design of Experiments (DoE) and proxy modeling were incorporated to find the most sensitive parameters that affect the GDWS-AGD process performance. The candidate parameters are porosity, horizontal and vertical permeability for each layer, radius of aquifer and rock compressibility.
In the GDWS-AGD, the produced water not only reduced water cut and coning, but also significantly reduced the reservoir pressure, resulting in improving gas injectivity. In addition, the GDWS-AGD process improved cumulative oil production. More specifically, the results showed that cumulative oil production increased from 3.8*105m3 to 4.7*105m3 and water cut decreased from 97% to 92% in all the horizontal oil producers. For the proxy model, it was cleared from Sobol analysis that the porosity for layer 5 was more influential parameter than others on cumulative oil through GDWS-AGD process with 31% main effects and 0.025% interaction effects, while the horizontal permeability for layer 4 was the most influential parameter with 24% main effects and 1.5% interaction effects. The novelty of GDWS-AGD process comes from its effectiveness to improve oil recovery with reducing the water coning, water cut, and improving gas injectivity. This leads to more economic implementation, especially with respect to the operational surface facilities.
Pitfalls of Surface Well Test Analysis - Guidelines
Authors: Hakim Bilal , Fair Chris 
Published: April 2019

Abstract
Pressure Transient Analysis (PTA) provides valuable information about the subsurface completion and reservoir. Permanent downhole pressure gauges (PDHG) are not always available in wells. In such cases, wellhead pressure (WHPG) gauges, or temporary downhole gauges (DHG) can be used to perform reservoir/completion diagnostics. Although in some cases it is safe to use raw WHP data for analysis, in a lot of cases it should not be done. Fair et al. (2002) presented a methodology to categorize wells that could be tested from the surface (well head) along with a methodology that allows surface-to-bottomhole pressure (BHP) conversion.
A few authors in the past have emphasized the importance of converting wellhead pressure and downhole gauge pressure data to mid-completion bottomhole conditions to account for friction and changing fluid density during a test. Performing PTA without correcting the gauge data for these wellbore effects can lead to inaccurate results: especially the over-estimation of skin and permeability, and underestimation of P*, and in-place hydrocarbon volumes, due to reservoir signal suppression. The WHP data could also be non-analyzable (using conventional methods) if the effects are severe. Hakim et al. (2016) further discussed the importance of this conversion and presented examples where WHP to BHP conversions in various types of wells could be performed with high accuracy using a coupled PVT-thermal wellbore model.
This paper will introduce the concept of rate of change in wellbore fluid density (wellbore signal) relative to the rate of reservoir pressure increase/decrease (reservoir signal) during a test. The purpose is to identify the factors affecting the "reservoir signal" in the measured wellhead pressure and rate data during a well flowback and during the commercial production period, and to provide guidelines to help the petroleum engineer determine the severity of these factors in a given well/reservoir system. This should help the petroleum engineer in deciding whether to rely on the WHP data or run a DHG to observe the reservoir signal.
A 3-step methodology to determine the magnitude of the wellbore signal relative to the reservoir signal will be presented with solved examples of an oil well and a gas-condensate well.
Permeability and Porosity Evolution of Organic Rich Shales as a Result of Heating
Authors: Kim Tae Wook , Ross Cynthia M. , Guan Kelly , Burnham Alan K. , Kovscek Anthony R. 
Published: April 2019

Abstract
Source rocks (oil shale) were matured artificially via pyrolysis under geologically realistic triaxial stresses using a unique coreholder that is compatible with X-ray Computed Tomography (CT) scanning. This study focuses on characterization of porosity and permeability as well as the evolution of shale fabric during pyrolysis. Experiments were conducted using 1-inch diameter vertical and horizontal core samples from the Green River Formation. Prior to pyrolysis, the properties of the source rock were characterized (e.g., porosity, bulk density, mineralogy, and TOC). Samples were then heated from room temperature to 350 °C under a nitrogen environment to obtain conversion of organic matter to oil and gas via pyrolysis. Porosity and permeability after maturation were measured. Micro-CT visualization was applied to investigate the fracture network developed throughout the core. Scanning electron microscopy (SEM) images were also used to compare the shale fabric and porosity evolution (pre- to post-maturation) at higher resolution.
In-situ observations reveal a decrease of average CT number (i.e., density) within some volumetric regions of the cores after maturation. In these regions, organic matter (kerogen and bitumen) were converted into hydrocarbons. Changs in the source rock depends on the original TOC fraction, hydrogen index (HI), and temperature. The permeability prior to pyrolysis for vertical samples is in the undetectable to nanodarcy range. The permeability of all cores increased to the microdarcy range post-maturation. In particular, the permeability of the horizontal sample increased from 0.14 to 50 μD. This improvement in permeability occurred due to the generation of open porosity and fractures (dilation, generation, and/or drainage). Additionally, the porosity after Soxhlet extraction increased proportionally by 20 % from pre- to post-pyrolysis depending on pyrolysis time and TOC fraction. Longitudinal deformation depends on the orientation of the sample with respect to the triaxial stress during pyrolysis. The deformation of vertically oriented samples with isostress conditions is larger than that of horizontally oriented samples with isostrain. The measured 3D in-situ porosity distribution indicates that organic matter has transformed into hydrocarbons by pyrolysis. The development of a fracture and matrix porosity system under stress provides an explanation for transport of hydrocarbon away from its point of origin.
Case Study: Natural Gas Storage in Federal Waters Offshore California
Authors: Ojukwu Chima , Smith Kevin , Kadkhodayan Nadia , Leung Mark , Dame Robert , Voskanian Armen 
Published: April 2019

Abstract
The U.S. Pacific Outer Continental Shelf (OCS) Region offshore California has over fifty years of production and development history. As of 2018, more than 1.35 billion barrels of oil and 1.85 trillion cubic feet of natural gas has been produced from three sedimentary basins in the Pacific OCS1. As part of the Bureau of Ocean Energy Management's (BOEM) mandate to sustainably manage development of U.S. OCS energy and mineral resources in an environmentally and economically responsible way, it is paramount that conservation and mixed-use projects such as underground gas storage be evaluated, adjudicated, and monitored to maximize utility of existing OCS offshore infrastructure. Through 2018, only a few underground gas storage projects have been undertaken in the entire U.S. Outer Continental Shelf (OCS) federal waters. The Sockeye Field Underground Gas Storage project in the Santa Barbara channel is a unique example of alternative reservoir use, as it is the only such project initiated and successfully executed in the Pacific OCS Region. Gas injection commenced short-term in 2002 and was effectively formalized in 2005 through an agreement between the Sockeye Field Operator and BOEM's predecessor agency, the Minerals Management Service (MMS). From the inception of the project through 2017, total gas volume injected and withdrawn was 2.3 Bcf and 582 Mcf respectively.
This paper presents the results of the reservoir modeling study prepared for the Sockeye Field gas storage project. In this integrated study, BOEM utilized available 3D post stack time-migrated seismic reflection data, digital well log data, production data, and other geologic information to develop a comprehensive structural and petrophysical model of the Sespe sandstone reservoir. This study scrutinized segmentation of the Sespe hydrocarbon reservoir and, the suitability of the Sespe reservoir for storage of produced natural gas from the Sockeye Field.
Frhe results of the reservoir modeling, operator's cumulative gas production and injection indicate this gas storage scenario provided an energy source for offshore facility operations, precluded the need for external gas buy-back, and lengthened the productive life of the Sockeye Field. In addition, this project also demonstrated that nearby analog reservoirs in the Pacific OCS may be suitable for future underground gas storage.