bluuebunny/crossref_metadata_2025_split huggingface dataset:
InSAR: Pro-Active Technology for Monitoring Environmental Safety and for Reservoir Management
Authors: Leezenberg Pieter Bas , Allan Malcolm E. 
Published: April 2017

Abstract
InSAR (Interferometric Synthetic Aperture Radar) is a technology used to measure changes in surface elevation between successive passes of orbiting satellites. These changes can be used to understand imbalances in the subsurface between fluid withdrawal and injection, as well as near-surface ruptures caused by failure of well integrity.
Satellites have recorded SAR data since the 1990s, and the data have become increasingly higher resolution and more frequently acquired. Combined with faster algorithms and processing chains for interferometry, this has enabled detection of smaller and faster changes at the surface. This in turn has caused a step-change in the usefulness of the data and the interpretations. The result is the ability to depend on the data to monitor the effects of production and injection processes almost continuously.
We review several cases to demonstrate the value of rapid revisit, high resolution InSAR. The first is the giant Belridge field in the San Joaquin valley of California, historically the poster child for this application. The diatomite reservoir rock has 60% porosity and is fluid supported. When equilibrium between injection to production is not maintained, the volume changes in the reservoir cause the ground surface to move up or down by amounts detectable with InSAR enabling a feedback loop for injection optimization. The field also has many wells with compromised wellbore integrity that can provide a pathway for reservoir fluids to move upwards towards the ground surface. When water, oil, or steam move out of the reservoir and into the overburden, a potential precursor can be detected provided InSAR is configured carefully. In the second case, InSAR also provides visualizations of ground level changes over a gas field: at the giant Groningen gas field in the Netherlands, long term InSAR time series measurements of elevation changes are used to constrain models about compaction and reactivation of buried faults. Parts of the field that are used for seasonal gas storage and charging/discharging cycles can also be effectively monitored.
Measurement of surface deformation by high resolution, fast revisit, optimized InSAR provides an insight into the reservoir and the efficiency of its management. It also provides an early warning of potential problems that, if not corrected, may result in harm to the environment. These step changes in quantity and quality of available InSAR data mean that the remaining barrier to being used for actionable insights is in the widespread inverse modeling of the surface data to sub-surface mass flows.
A Case History on California Immiscible Gas Injection, Elk Hills Field
Authors: Kostelnik Keith , Arredondo Pedro , Montenegro Ana 
Published: April 2017

Abstract
The Elk Hills field has produced more than 1.9 billion barrels of oil equivalent with 555 million barrels from the Eastern Shallow Oil Zone (ESOZ) since discovery in 1919. The longevity and success of the ESOZ reservoir is attributed to the introduction of immiscible gas injection. The ESOZ structure is a plunging anticline with a relatively flat crest and steeply dipping flanks. On the northern half of the structure a salt water aquifer encroached up structure providing the majority of the energy for the oil produced prior to the implementation of gas injection. The energy in the reservoir was eventually depleted at which point gravity drainage and gas cap expansion, in the form of gas injection, became the primary drive mechanisms.
This paper will focus on one fault block within the field and highlight the efficiencies seen from up-dip immiscible gas injection in the presence of a down-dip aquifer.
Separating Solids First - Design and Operation of the Multiphase Desander
Authors: Rawlins C. Hank 
Published: April 2017

Abstract
Sand production is a common challenge for processing facilities and well test equipment, as solids degrade the mechanical integrity and separation efficiency of surface equipment through erosion, settling, and plugging. Where exclusionary sand control methods fail or do not exist, inclusionary surface handling methods can be used to maintain or increase the total hydrocarbon production. The best approach is to remove sand at the wellhead, which protects all downstream flow lines and equipment. The multiphase (wellhead) desander was developed in the late 1990s as a unit operation to separate solids at wellhead conditions. This technology has been deployed in onshore and offshore production, well cleanup, and well testing operations. In addition to protecting downstream equipment, wellhead desanding enables the easier design and operation of solids-handling systems.
Multiphase desanders were developed from solid-liquid cyclones used in the mining industry. Laboratory and pilot-plant tests conducted in 1994-1995 defined an initial hydraulic model, which was applicable in mixed-phase flow. The liquid-based model was paired with a dense-gas pneumatic cyclone model. The pressure drop and solids removal efficiency of the resulting multiphase model were evaluated at the Wytch Farm producing facility in Dorset, UK in 1995. This approach continues to be refined using field data, and the current mechanistic-empirical model has a high accuracy across the 0-100% gas void fraction range. The hydraulic and pneumatic models are discussed with respect to the pressure drop, solids removal, turndown, and slugging.
Mechanical design improvements, including material selection, construction to API-6A code, and apex-flux balancing, have doubled the multiphase desander operating life while reducing the size and weight by 40%. Design improvements are discussed with respect to the system layout and proper operation. A comparison is made between single and multiple cone vessel designs with respect to the particle size, solids concentration, and fluid partitioning.
Positive Correlation Between Historical Oil Production and Well Stimulation Response
Authors: Jamali Ali , Ettehadtavakkol Amin , Fan Dian , Moallem Golnaz 
Published: April 2017

Abstract
This paper proposes the use of spatial analysis of stimulation treatments and historical oil production to improve the selection of future candidate wells for workover treatments. Oil production data from four mature leases of the San Andres carbonate reservoir in the West Texas Permian Basin are analyzed to identify a potential correlation between historical oil production and the oil production improvement from well stimulation. Spatial grouping of producers is used to eliminate the bias introduced into the data because of workover failure, errors in production data, ongoing water and CO2 floods and other factors affecting the two correlated parameters. The spatial grouping approach is further extended to a semi-automated method for large datasets using the meanshift algorithm. To increase the robustness of the results, the analysis is repeated with ordinary kriging as an independent method.
The results obtained from both methods confirm the presence of a positive correlation between the historical oil production and the well response after the stimulation. The results are also compared with porosity-height maps, indicating that wells located in zones with better porosity-height have better stimulation response. This has important implications in identifying wells with greater potential for oil production improvement from well stimulation. While the success of the treatment strongly depends on the selection, design, and implementation of the appropriate stimulation method, priority should be given to the wells that exhibit high historical oil production, or the wells located in highly productive zones. This practice will statistically increase the likelihood of maximized workover benefits. The presented analysis used the oil production data from the San Andres carbonate reservoir; however, the proposed method is applicable to gas reservoirs and unconventional reservoirs.
An Integrated Workflow for Completion and Stimulation Design Optimization in the Avalon Shale, Permian Basin
Authors: Ajisafe Foluke , Shan Dan , Alimahomed Farhan , Lati Shrutesh , Ejofodomi Efe 
Published: April 2017

Abstract
In the Permian basin, unconventional reservoirs have been the main target of horizontal well drilling since the early 2000s. Over the years, completion design in horizontal wells has evolved from conservative to radical designs. The main purpose of this paper is to evaluate different completion and stimulation design scenarios to understand their impact on hydraulic fracture geometry and production performance. This paper is an extension of a previous work presented by Ajisafe et al. at the 2016 SPE Hydraulic Fracturing Technology Conference (SPE-179130-MS) on the use of discrete fracture network from seismic data for complex fracture modeling.
In most unconventional plays, the existence and interaction of the discrete fracture network (DFN) and hydraulic fractures during a stimulation treatment creates a complex fracture geometry. In the present study, seismic data provided an improved DFN model along and particularly away from the wellbore. The microseismic events showed variation in hydraulic fracture complexity and geometry along the lateral of the subject horizontal well.
A multidisciplinary integrated workflow was applied to the horizontal well to model complex hydraulic fractures and production. The DFN model and geomechanical properties were key inputs into the unconventional fracture model (UFM) and were constrained with the microseismic data and production history. After the UFM model was created, different sensitivity categories such as proppant job size, cluster spacing, and maximum proppant concentration, were investigated for their impact on the complex fracture geometry as well as production performance.
The field is an expensive laboratory. The use of advanced hydraulic fracture and reservoir simulation models can help provide the best completion design options from the start of field development as opposed to executing multiple field tests to determine the optimal design. The optimal completion design to increase hydrocarbon production with proper economics evaluation is critical for maximized returns. Single-well optimization is an important step in the unconventional workflow, and ultimately for better planning of multi well pad and infill well development.
Assessing Current and Potential Basin Assets Using an Innovative Predictive Analytics Workflow
Authors: Gbededo Midowa , Stone Mindy , Beaver Philip , Lee Young Jin 
Published: April 2017

Abstract
Recent changes in the global oil and gas economic environment have provided added incentives for E&P companies to utilize the massive pool of data being generated from oil and gas operations (Schuetter, et al. 2015, Stone 2007). There is an ever-growing need to enhance engineering and business decisions through insights from data that are being gathered and to justify the resources being utilized by companies in acquiring, processing and storing large pools of oilfield data (Shimbo 2008). This paper asseses oil wells at a basin level by demonstrating a predictive analytics workflow from an engineering and financial perspective.
In this paper, assessment of oil assets is approached from both asset management and asset acquisition perspectives. A number of data sets will be combined to gain insights into trends of oil and gas assets in the Williston Basin. All data sets used are publicly available and they include: monthly basin production, financial reports (10-Ks), monthly oil prices and U.S energy information administration's historical/projected basin well costs. Using the "Cross-Industry Standard Process for Data Mining" (CRSIP-DM) workflow (Abbott 2014), the analysis is broken up into: Engineering insights: key predictors for well productivity in the Williston basinFinancial insights: assessing oil operations from a financial perspective.
The first step was generating predictive models for well production performance in the basin. Basin assets are then assessed financially to identify the most lucrative assets in the basin along with engineering practices for said assets and their locations.
Key predictors of oil well production performance across the basin were identified using this workflow. Each predictive model generated is assigned a predictive accuracy. Proppant volume was a driver in high performing wells. On a basin wide level, producing formation and county were the two most important predictors for oil well performance.
Candidate Trees for Terrestrial Carbon Storage in Regions with High Air Pollution and High Water Stress
Authors: Saini D. 
Published: April 2017

Abstract
The State of California has now passed a new executive order to reduce, greenhouse gas (GHG), emissions by 40% below 1990 levels by 2030 and 80% below 1900 levels by 2050. A significant portion (37%) of GHG emissions in California comes from non-point sources (i.e. various modes of transportation). Terrestrial carbon storage (i.e. taking the advantage of inherent ability of certain tree species for storing carbon) for reducing the concentration of carbon dioxide (CO2), which is major GHG, from atmosphere is one of many ways to tackle the problem of GHG emissions resulting from non-point sources.
In this project, research was focused on finding candidate trees that are drought resistant, native to California, and could continue to sequester atmospheric carbon dioxide in significant quantity over an extended period (&gt;100 years). Several forestry databases were searched for gathering a list of 37 candidate trees. The list was further narrowed downed to 13 which are fast-growing (i.e. reaching reported minimum height for a mature tree in 10 years or less time), emit low to moderate biogenic emissions, can grow in in USDA hardiness zone 8 or above, and have a width less than 20 ft when fully matured. Lastly, 7 candidate trees that are considered big as well as urban trees, are native to Southern California, were identified as the most suitable candidate trees for terrestrial carbon storage in regions with high air pollution and high water stress.
Based on simplistic estimates of CO2 absorption per tree per year, it is estimated that a total of 186,000 acres of new forest comprising of top candidate trees identified in the study can help in achieving a 10% reduction in the GHG emissions occurring from transportation sector in the Kern County, California, and a 20% reduction in the Fresno County, California within 10 years of forestation.
Electrical Resistivity Autonomous Inflow Control Device ER-AICD
Authors: Jadhav Nachiket , Zhambrovskii Dmitrii 
Published: April 2017

Abstract
As it becomes necessary to drill long horizontal extended reach wells to reach out for thin oil rim reservoirs, it also has its own challenges. Usage of new technologies and their implementation in terms of cost efficiency and increased reservoir performance is the primary objective. While producing through horizontal wells there is always a possibility of breakthrough of unwanted water or gas compromising the production of oil and to some extent leaving some valuable oil reservers behind. The reason behind this is that the heel of the well produces at higher rate than the toe because toe has to overcome the frictional pressure losses due to increased pressure drop along the horizontal length of the well.
To tackle this problem Inflow Control Device (ICD) was introduced which will delay the early breakthrough of water or gas. There are different designs of ICDs available in the industry which significantly delays the breakthrough. Most ICDs provide flow restriction for the produced fluid to create uniform inflow profile along the entire length of the wellbore. However, due to uncertainties in reservoir properties there might be water or gas inflow through ICD and no existing ICDs can reverse this problem undermining the optimization of oil production.
This paper presents the design of Electrical Resistivity Autonomous Inflow Control Device (ER-AICD) that on a par with creating uniform inflow profile along the wellbore; it opens and closes the valve when there is oil, water or gas inflow correspondingly. The device will work on the principle of electrical resistivity of reservoir fluids, resulting in more flexibility in downhole operations and optimizing oil production as a whole.
Mobilization of Trapped Residual Oil via Secondary SAGD with Propane
Authors: Kar T. , Nezhad P. B. , Ng A. Z. , Ovalles C. , Benson I. P. , Hascakir B. 
Published: April 2017

Abstract
Solvent- Steam Assisted Gravity Drainage (S-SAGD) processes for bitumen extraction are proposed to reduce the environmental impact of steam injection. S-SAGD processes require more research due to the unknowns of solvent-bitumen interaction and the desire to reduce the cost of steam and solvent utilized. This study investigates propane-SAGD (P-SAGD) and propane-steam flooding (P-SF) performance for the recovery of a Canadian bitumen from Alberta with 9.6 API gravity, 290,500 cP viscosity (at 25 °C), and 21.7 wt% asphaltenes (n-pentane insoluble) content. Three two-dimensional SAGD experiments (one SAGD and two P-SAGD at two different propane doses) and three one-dimensional flooding experiments (propane, steam, and propane-steam) were conducted. By comparing 2D experiments with 1D, we were able to analyze the effect of continuous steam flow and steam chamber development on process performance in microscopic scale. Water and asphaltenes contents of produced oil were measured. It has been observed that the steam chamber development with propane coinjection enhanced the oil production, however, led to delay in oil production compared to the steam flooding case. Thus, we also tested first steam injection until achieving the communication between the injector and producer in SAGD configuration and then, switching to steam-propane coinjection. After allowing the steam-bitumen interaction first, propane injection did not result in severe water-in-oil emulsion formation. Moreover, lesser permeability reduction due to asphaltenes deposition was observed. The application of propane-SAGD as follow up to SAGD improved the process by the mobilization of trapped residual oil and enhanced the quality of produced oil by minimizing the formation of water-in-oil emulsion.
Producer Well Temperature Control and Optimal Oil Production During a Steamflood
Authors: Agarwal Anshul , Kovscek Anthony R. 
Published: April 2017

Abstract
Steam injection is an important method for recovery from heavy-oil reservoirs. A major issue for steam flood operations is the high temperature at the producer well after steam breakthrough. Surface facilities need to be equipped with procedures to handle hot fluids exiting the well head. Wells are sometimes shut in for safety or other practical reasons because they are too hot. There are multiple parameters that influence producer temperature. The focus of this paper is to study the impact of injected steam quality and pressure using reservoir simulation. We find that a combination of high-quality and high-pressure steam injection conditions, followed by injection of steam at reduced quality and reduced pressure achieves larger cumulative oil recovery and reduces producer operating temperature thereby avoiding shut-in.
Steam injection at reduced quality, and at lower temperature and pressure, prolongs the producing time of the field, thereby increasing the cumulative volumes of oil recovered. Injection of low quality steam, however, increases operating costs with larger water consumption for steam (CWE) and a larger water production for disposal or reuse. On the other hand, the greater the steam quality, the greater the energy required (BTU) for steam generation. To investigate such tradeoffs, we used a commercial simulator to model a hypothetical layered reservoir with a steam injector and two producers. A steam of quality 1 at 800 psi is injected initially, followed by injection of a lower quality and/or lower pressure/temperature steam in order to keep the producer well temperature below 450 °F at all times.
Our systematic study of steam pressure or temperature and quality leads to the following observations for the particular reservoir characteristics: (i) Reducing steam pressure and quality led to lower cumulative produced oil volume, with better temperature control at the producer well; (ii) For the same amount of energy injected (in BTU units), higher steam quality produced more oil, but led to elevated temperature at the producers and shutting-in of the wells; and (iii) Steam flood with alternating periods of high- pressure, high-quality injection and periods of lower pressure injection led to continuous oil production with producer temperature control. The hybrid injection schedule consists of a combination of alternating high-quality and high-pressure steam flood, followed by reduced steam quality and reduced pressure. Importantly, larger cumulative oil production with lower cumulative energy and water injection resulted from hybrid injection. We also include geomechanical effects to assess any impact of pressure variations and conclude that the hybrid injection strategy is a promising solution for heat control at producer wells.
Heavy Oil Recovery from Opal-CT Diatomite
Authors: Dietrich J. K. 
Published: April 2017

Abstract
Diatomite oil reservoirs are unconventional. They hold billions of barrels of oil in a tight rock matrix with unusual physical properties, and contain a stress-sensitive natural fracture system that introduces a strong permeability anisotropy during fluid injection. Perhaps the most unusual feature of diatomite is geochemical in nature. Diatomite undergoes a silica-phase reordering and transformation as temperature is raised, whereby amorphous Opal-A is converted to a more ordered Opal-A' and more dense, crystalline Opal-CT. The injection of steam accelerates this naturally occurring process and leads to rapid densification and compaction and an irreversible loss of permeability.
Nearly all of the field projects have been installed in Opal-A. Opal-CT is less permeable and this is the primary reason its development has been deferred. Although Opal-CT is less permeable under initial reservoir conditions, its stress and temperature-dependent compaction coefficients are much lower than those of Opal-A. As steam injection elevates reservoir temperature over time, the difference in permeability of Opal-A and Opal-CT is expected to narrow. It is chiefly for this reason that Opal-CT may hold more promise than currently supposed.
The Opal-A field projects have demonstrated that closely spaced rows of wells are necessary for efficient oil recovery by water or steam injection. What is now called ultra-tight well spacing with rows of hydraulically fractured injectors and producers spaced only 35 to 45 feet apart was shown via numerical modeling more than 20 years ago to be necessary for maximizing oil recovery. That early modeling made use of laboratory determined rock and fluid properties and included the effects of thermally induced compaction. Following tuning of the early models using hydraulically fractured cyclic steam response, they were used to estimate ultimate recovery and thermal efficiency for steam injection into diatomite containing heavy oil. Given Opal-CT and ultra-tight well spacing, a combined cyclic steam and steamflood process was shown to be capable of ultimately recovering about 40% of the original oil-in-place, with a CSOR of 3 to 4 barrels of CWE steam per barrel of oil.