bluuebunny/crossref_metadata_2025 huggingface dataset:
The Impact of the Hydraulic Fracture Properties on the Gas Recovery from Marcellus Shale
Authors: El Sgher M. , Aminian K. , Ameri S.
Published: April 2017

Marcellus Shale, a Devonian black shale, spans the majority of the Appalachian Basin from New York through Pennsylvania, West Virginia and also extends into Ohio and Maryland (Bartuska, et al. 2012). The unconventional gas reservoir is a term commonly used to refer to ultra-low permeability formations that produces mainly dry natural gas and is not able to produce an economic flow rate without stimulation treatments. The natural gas in the Marcellus Shale is produced most efficiently through horizontal wells with multiple hydraulic fracturing stimulation treatments. Even though advances in technology have unlocked considerable reserves of hydrocarbon, the long-term production behavior of the horizontal wells with multiple hydraulic fractures is not well understood. This paper provides the results of parametric studies to investigate the impact of the hydraulic fracture properties and more specifically the impact of non-uniform fracture half-length, on the gas recovery from Marcellus Shale.

The purpose of this study is to evaluate the long-term production performance of horizontal wells with multiple hydraulic fractures completed in Marcellus Shale. A commercial reservoir simulator was used to develop the base model which incorporated the storage and production mechanisms inherent in shales. The core, log, completion, stimulation, and production data obtained from wells located at the Marcellus Shale Energy and Environment Laboratory (MSEEL) were utilized to generate the simulation model. MSEEL is a research collaboration between West Virginia University, Ohio State University, The Natural Energy Technology Laboratory, and Northeast Natural Energy. MSEEL aims to achieve a better understanding of the unconventional shale resources through application of advanced technology in drilling, completion, reservoir characterization, production and monitoring of horizontal wells. Furthermore, fracture properties (fracture half-length, fracture width and fracture conductivity) were obtained by using commercial software. Precision laboratory equipment was utilized to determine the shale properties from the core samples.

Field production data from two original horizontal Marcellus Shale gas wells at MSEEL site were utilized for history matching to establish the missing shale parameters. History matching was initially performed using production data for two years from one the horizontal wells. The matched model was then used to predict the production for the following two years to confirm the accuracy and reliability of the model. In addition, the base model was used to predict the second horizontal well production which provided reliable results. Finally, a number of parametric studies were performed with the model to investigate the impact of the hydraulic fracture properties and non-uniform fracture half-length, on the recovery.
Conditioning Multiple-Point Geostatistical Facies Simulation on Nonlinear Flow Data Using Pilot Points Method
Authors: Ma Wei , Jafarpour Behnam
Published: April 2017

A new implementation of the pilot points method is introduced for conditioning discrete multiple-point statistical (MPS) facies simulation on dynamic production data. In MPS simulation, a conceptual model of geologic connectivity, known as a training image (TI), is used to simulate instances of facies distributions that are statistically consistent with those encoded in the TI. While conditioning MPS simulation results on static hard (e.g., core) and soft (e.g., 3D seismic) measurements is relatively straightforward, calibration against nonlinear production data is nontrivial. The pilot points method is a convenient parameterization approach in which production data are used to obtain facies values at a number of strategically selected grid blocks (pilot points). An important issue in using the pilot points method is strategic placement of the pilot points in the domain. To this end, we propose combining three sources of information to generate a score map for placing the pilot points: (i) the uncertainty in facies distribution, (ii) sensitivity information, and (iii) production data. Once the pilot points are located, the facies values at these points are inferred from production data and are used, along with available hard data at well locations, to simulate a new set of conditional facies realizations. While facies estimation at the pilot points can be performed using different inversion algorithms, in this study the ensemble smoother with multiple data assimilation (ES-MDA) is used to update permeability maps from production data, which are then used to statistically infer facies types at the pilot point locations. The developed method combines the information in the production data and the TI by using the former to infer facies values at select locations away from the wells and the latter to ensure consistent facies structure and connectivity where the production data may be inconclusive (e.g., away from measurement locations). The performance of the developed method and its important properties are evaluated and discussed using numerical experiments.
Oilfield Scale Removal by Chelating Agents: An Aminopolycarboxylic Acids Review
Authors: Almubarak Tariq , Ng Jun Hong , Nasr-El-Din Hisham
Published: April 2017

This literature review summarizes the theory and application of chelating agents in scale removal. The objective of this work is to give the reader a better understanding of scale removal methods by chelating agents in oil field applications.

This paper reviews results that were obtained through various laboratory tests, which aid in understanding chelating agent interactions with formation rock and formation fluids. Results were obtained through a variety of tests including compatibility, dissolution, Inductively Coupled Plasma (ICP), Environmental Scanning Electron Microscope (ESEM) and X-Ray Diffraction (XRD).

At high temperatures, conventional acids such as hydrochloric acid (HCl) show severe corrosion, lack of penetration and sludging characteristics. Several organic acids were proposed to solve these issues. However, even organic acids result in solubility and incompatibility issues. Based on these shortcomings, chelating agents are often used and show good dissolving power, low corrosion, low sludging tendencies, excellent iron control, and some are highly degradable and environmentally friendly. In addition, chelating agents are commonly used to dissolve most oil field scales that are both insoluble in HCl and detrimental to production.

This work summarizes the applications of chelating agents in the stimulation sector, including the latest developments and field applications of chelating agents. Readers can easily expand on this paper to further explore the wide range of applications chelating agents can offer the oil and gas industry.
A New Method of Calculating Rig Parameters and its Application in Downhole Weight on Bit Automation in Horizontal Drilling
Authors: Wu Z. , Hareland G. , Loggins S. M. , Lai S. , Eddy A. , Olesen L.
Published: April 2017

On most onshore rigs, weight on bit (WOB) is usually obtained from the deadline hook load measured by deadline the sensor installed on the deadline of the block-and-tackle system. To obtain a more accurate WOB, a measurement tool, called torque and tension sub (TTS), has been developed to measure the load below the quill of a top-drive system. Theoretically, the load from the TTS, called the TTS hook load, is more accurate than the deadline hookload because the TTS measurement is not affected by the friction between the drilling lines and sheaves and the top drive rails. The downhole weight on bit (DWOB) is a key parameter in optimizing rate of penetration (ROP) and drilling optimization because accurate DWOB plays a very important role in improving the overall performance of a bit run. The objective of the work presented herein is to acquire rig parameters such as sheave efficiency, static weight of travelling block and friction between top drive and the rail by using theoretical analysis and regression analysis of acual drilling data. These parameters can further be used for DWOB automation calculation, which will greatly improve the overall drilling efficiency and save drilling cost.

A set of drilling data was collected from a well in western Canada, including bit depth, hole depth, deadline hookload, TTS hookload, surface measured WOB and standpipe pressure. Force analysis to the upper part of a top drive system was conducted, and a theoretical equation derived which reflects the relationship between the deadline hook load and the TTS hook load. An empirical relationship is also obtained by regression analysis of the drilling data.

The results show that there is a good agreement between the theoretical equation and the empirically-derived relationship. Therefore, the empirical relationship can be used to get the sheave efficiency, static weight of travelling block and friction between the top drive and the rail.

The relationship between the deadline hook load and TTS hook load established in this paper brings about a new method to acquire rig parameters which are usually obtained by experience or a rule of thumb. This will potentially improve the calculation of DWOB automation. The proposed new correlation method will find a wide range of potential applications, such as on new types of automation drilling systems being developed in the drilling industry, which is especially suitable for horizontal drilling.
Midway-Sunset 35Z Case Study: A Journey from Geo-Cellular Grids to Field Operations
Authors: Ardali Mojtaba , D'Cruz Ryan , Erickson Telann , Moustakis Michael , Salameh Mourad
Published: April 2017

The Olig heavy oil zone at 35Z is a shallow dipping reservoir with estimated oil in place of more than 20 MMBO and upside potential of 50-70% oil recovery with an optimal depletion strategy. The successful thermal development at Midway-Sunset section 35Z was facilitated by early collaborative reservoir characterization and modeling efforts. In this study, integrated subsurface mapping, petrophysical analysis and modeling technology were utilized to estimate the potential of the Olig sands and evaluate various field development options. The multidisciplinary effort between petrophysicists, geoscientists and engineers analyzed and integrated various sources of data into a full-field geological model. The model was calibrated and used to investigate various field development strategies. This work allowed the team to identify a development scenario that maximized both oil recovery and capital efficiency. The study led to technical recommendations that were implemented in 35Z Midway-Sunset field operations. The main deliverables of the study were as follows: Well spacing for any short-term and long-term thermal development was switched to 2-Acre spacing from original 1-Acre spacing. Therefore, the proposed number of wells drilled were reduced by almost half, resulting in significant capital cost savings.Modeling work quantified various long-term field development options. While Cyclic Steam Injection (CSI) provides significant oil recovery, continuous steam injection offers significantly higher oil recovery. Crestal steamflooding is superior compared to pattern steamflooding if geological continuity is confirmed.

The early characterization and modeling work on the 35Z Olig informed the team's decision-making and helped grow the area from a 6-well pilot to an economic full-field thermal development in less than 2 years.
InSAR: Pro-Active Technology for Monitoring Environmental Safety and for Reservoir Management
Authors: Leezenberg Pieter Bas , Allan Malcolm E.
Published: April 2017

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

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

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

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

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

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

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 (>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

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

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

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

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.
Application of the Galerkin's Finite Element Method to the Flow of Power-Law Non-Newtonian Fluids through Porous Media
Authors: Omosebi O. A. , Akabogu A. K.
Published: April 2017

Conventional approach of modeling fluid flow through porous media and analysis of pressure data often adopt a simplified approach by assuming a Newtonian fluid flow behavior. However, most of the fluids encountered in the oilfield exhibit non-Newtonian flow characteristics. Analysis of field data involving these fluids with conventional Newtonian flow models would result in erroneous interpretation. The generalized equation for the radial flow of non-Newtonian fluids through porous media has been solved analytically but a numerical solution by finite element is yet to be published. In this study, the Galerkin Finite Element technique is used to solve the generalized problem under the various inner and outer boundary conditions that are frequently encountered in the oilfield.

Weak formulation of the generalized PDE and boundary conditions is obtained and is discretized into finite elements. Element matrix in both the spatial and time domains are computed using Gauss quadrature technique. Subsequently, the nodal pressure values are computed and a derivative function is used to compute the corresponding pressure derivatives. A commercial simulator is used to verify the numerical solution for the conventional Newtonian fluid flow. The numerical solution is also compared to approximate analytic solutions involving non-Newtonian fluids.

Results show the commonly observed flow regimes in pressure transient testing, which include the early-time unit slope line (wellbore storage), the early-time trough signifying pseudo-steady state matrix fracture flow (naturally-fractured reservoirs), the infinite-acting radial flow regime line, and the late-time boundary-dominated footprints for no-flow boundary, constant-pressure boundary, and pseudo-steady state (closed reservoir system). The solution obtained in this study matches the numerical solution from a commercial simulator. Comparison of the numerical solution with approximate analytic solutions also shows strong agreement. Validation of the finite element solution with field data involving polymer injection shows a satisfactory match. Parametric study of the effect of fluid flow index indicates the strong dependence of pressure transient and characteristic flow regimes on fluid rheology.

Limited studies have established the application of finite element technique in modeling non-Newtonian fluid flow through porous media. This study demonstrates how the generalized fluid flow model can be solved by finite element method.
Workover Well Operations to Restore Full Reservoir Access in an Underground Natural-Gas-Storage Cavern: A Case Study for Developing New Technology in Dual-String Section Milling Methods
Authors: Smalley Michael T. , Teale David W. , Haq Mohammed A.
Published: April 2017

Both above and under the ground, hydocarbon storage is subject to many stringent compliance standards regarding health, environment, and ground water safety. Various issues—such as zoning regulations, future expansion needs, secondary and tertiary containments, design efficiency for storage and transfer, and financial viability of projects—determine the storage installation method. Underground storage maximizes real estate usage, reduces fire hazards, protects against weather events, and enables storing large amounts of hydrocarbons. The principal methods for underground storage include salt caverns, depleted reservoirs, and acquifers. Each method has its own application advantages and physical properties, such as retention capability and permeability. These factors, along with the economics of site establishment and maintenance as well as deliverability rates, regulate the suitability of that method for particular applications. For example, salt caverns provide very high withdrawal and injection rates relative to their working gas capacity. When the operator locates a suitable salt dome or salt bed, the site is excavated to form a cavern. This excavation process is usually accomplished by pumping or injecting highly pressurized water into the salt layer to dissolve the salt and create a cavern cavity; this method is referred to as cavern leaching or solution mining. After this process, the operator can remove the brine and commence operations.

However, if this leaching phenomenon occurs in existing natural gas storage caverns, the leached area behind the intermediate casing becomes an inaccessible part of the reservoir. To access this area, the lower section of this casing must be removed. Traditional section milling can achieve this; but if the inside diameter (ID) of the inner string is smaller than the outside diameter (OD) of the servicing tool, existing technology cannot be used. Situations such as this require new technology to pass through the restricted ID and open a section in the next-larger-size string.
A Distance Transform Method for History Matching of Discrete Geologic Facies Models
Authors: Elahi Siavash Hakim , Jafarpour Behnam
Published: April 2017

Construction of predictive reservoir models involves subjective interpretation and interpolation of spatially limited data, often using imperfect modeling assumptions. Hence, the process can introduce significant uncertainty and bias into production predictions. In particular, the uncertainty associated with the facies distribution in complex geologic environments, such as fluvial channels, can be consequential for production forecasting and reservoir development planning. Conventional history matching techniques are mainly designed to update continuous reservoir properties, such as permeability and porosity distributions. As such, calibrating discrete facies against production history may require a parametrization approach to convert discrete facies to continuous parameters. In this paper, we present a distance transformation method for calibrating the distribution of discrete facies againts production data. Distance-based transforms are widely used in discrete image processing, where the discrete values in each image pixel are replaced with their distance (i.e., a continuous variable) to the nearest cell with a different value (i.e., facies boundary). The history matching is then performed by updating the continuous distance maps based on observed production data. Once the distances are updated, an inverse distance transform is applied to convert them back to discrete facies models. The distance transformation enables discrete facies updating with history matching techniques that are designed for continuous variables, while ensuring that the final solution remains discrete. A low-rank representation of the continuous distance maps with the truncated singular value decomposition (SVD) is also presented for problems in which large-scale facies connectivity is expected. In that case, the production data is used to update the low-rank SVD projection coefficients of the distance maps. The developed discrete transformation ensures that the solution of the facies model calibration problem remains discrete. Furthermore, the use of prior models and SVD parameterization help to preserve the connectivity in the geologic facies after dynamic data integration. Examples with two and three facies models are used to illustrate the application of the method and to evaluate it performance.
Material Balance Applied to Dynamic Reservoir Surveillance Patterns
Authors: Batycky Rod P. , Thiele Marco R. , Razavi Mahdi
Published: April 2017

Determining the remaining spatial oil saturation distribution and current reservoir pressure distribution for a mature (water, solvent, CO2) flood is a cornerstone of reservoir management associated with improving sweep and selecting infill well locations. Decisions of this type are typically supported by reservoir flow simulation models that have been calibrated to the historical injection/production data.

In this paper, we present a material balance based approach to estimating remaining fluids in place as an alternative to using flow simulation. First we use the historical injection/production volumes to solve for streamlines and streamline derived pattern metrics such as well allocation factors and injector/producer well-pair reservoir volumes. Then we apply material balance on these volumes over time to estimate spatial fluid saturations and pressures existing at the end of history. Like reservoir simulation, the method accounts for changing well patterns through time, requires a 3D static geological model, and yields 3D saturation distributions of oil, water, and gas. However, unlike reservoir simulation the only calibration (history matching) required is the approximation of pore volumes and initial fluids in place of the patterns.

We present results for simple 2D models to illustrate the approach and compare to results from flow simulation. We then present a 3D pattern water/gas flood and the remaining oil and gas in place maps that are computed. The advantage of our method is that minimal history matching is required as historical injected/produced volumes are used explicitly; the disadvantage is that the resulting 3D saturation distributions are less detailed because the control volumes used for material balance are defined at the well-pair level which are many times larger than individual grid cells.
Efficient Modeling and History Matching of Shale Oil Reservoirs Using the Fast Marching Method: Field Application and Validation
Authors: Iino Atsushi , Vyas Aditya , Huang Jixiang , Datta-Gupta Akhil , Fujita Yusuke , Bansal Neha , Sankaran Sathish
Published: April 2017

This paper demonstrates the novelty and practical feasibility of the FMM-based multi-phase simulation for rapid field-scale modeling of shale reservoirs with multi-continua heterogeneity.

Modeling of unconventional reservoirs requires accurate characterization of complex flow mechanisms in multi-continua because of the interactions between reservoir rocks, microfractures and hydraulic fractures. It is also essential to account for the complicated geometry of well completion, the reservoir heterogeneity and multi-phase flow effects. Currently, such multi-phase numerical simulation for multi-continua reservoirs needs substantial computational time that hinders efficient history matching and uncertainty analysis. In this paper, we propose an efficient approach for field scale application and performance assessment of shale reservoirs using rapid multi-phase simulation with the Fast Marching Method (FMM).

The key idea of the reservoir simulation using the FMM is to recast the 3-D flow equation into 1-D equation along the ‘diffusive time of flight’ (DTOF) coordinate, which embeds the 3-D spatial heterogeneity. The DTOF is a representation of the travel time of pressure propagation in the reservoir. The pressure propagation is governed by the Eikonal equation which can be solved efficiently using the FMM. The 1-D formulation leads to orders of magnitude faster computation than the 3-D finite difference simulation. The use of FMM-based simulation also enables systematic history matching and uncertainty analysis using population-based techniques that require substantial simulation runs.

We first validate the accuracy and computational efficiency of the FMM-based multi-phase simulation using synthetic reservoir models and comparison with a commercial finite-difference simulator. Next, we apply our proposed approach to a field example in Texas for a multi-stage hydraulically fractured horizontal well. The 3-D heterogeneous reservoir model was built and history matched for oil, gas and water production using the Genetic Algorithm with the FMM-based flow simulation. Multiple history-matched models were obtained to examine uncertainties in the production forecast associated with respect to the properties related to hydraulic fractures, microfractures and the matrix.