bluuebunny/crossref_metadata_2025 huggingface dataset:
Measuring Marcellus Shale Petrophysical Properties
Authors: Zamirian M. , Aminian K. , Ameri S.
Published: April 2016

The advances in hydraulic fracturing and horizontal well technology have unlocked considerable reserves of hydrocarbon contained in shale formations. However, quantification of the key shale petrophysical properties remain challenging. It is not practical to measure the permeability of the unconventional formations such as shales by standard steady state techniques because shales typically have permeability values in nano-Darcy range. Therefore, unsteady state methods have been extensively used to estimate permeability of the shale samples. However, the measured permeability values by these techniques suffer from large margin of uncertainty and reproducibility problems. These problems are attributed to the lack of consistent experimental protocols and the interpretations of the transient data. Another limitation of the unsteady-state measurements is that the experiments cannot be performed under the reservoir stress and temperature conditions.

This paper provides the results of the porosity and permeability measurements on Marcellus shale core plugs which were performed using a fully automated laboratory set-up for evaluation of the ultra-low permeability petrophysical properties under the confining pressure. The permeability of the core plug were first measured under different gas pressures at constant net stress. The absolute permeability was then determined by applying the gas double-slippage correction. The porosity and the permeability of the core plug were then measured under a wide range of net stress. The measured porosity and permeability values were found to be sensitive to stress. Two distinctive behaviors with net stress, for both porosity and permeability, were observed that can be related to the natural fracture and matrix properties. The experimental results were then utilized to determine the natural fracture closure pressure. The permeability measurements with carbon dioxide revealed that permeability is impacted by adsorption. The results of the measurements with were carbon dioxide also provided information for determination of the sorption characteristics that were found to be in agreement with the published values.
A Computational Study of Packoff Using a Combined Drill Bit Stabilizer Particle Tracking Simulation
Authors: Uddin H. , Choudhury N. R. , Ansari U.
Published: April 2016

The primary cause of packoff in wells is improper hole cleaning resulting from aggregated cuttings and particles from the bottom hole. Drill-bit geometry and rotation plays an important role in dictating returning flow paths of drilling mud and thus transportation of debris particles from the bottom hole. This paper presents an early attempt to investigate the integrated effect of mud flow through drill bit and stabilizer slots on well packoff using computational fluid dynamic (CFD) -based particle simulations.

A commercially available three-dimensional (3D) flow solver was used to simulate turbulent flow for both stationary and rotating drill bits and two competing stabilizer designs with different flow by area. The motion of debris was tracked using a discrete phase model in a Lagrangian framework. A set of parametric studies was performed to investigate the effect of stabilizer location, particle size, rate of penetration (ROP), etc. on the hydraulic performance of the integrated assembly in terms of cuttings-transport ratio [the ratio of average particle velocity to average annulus velocity (Ct)], particle concentration, velocity profiles, etc. for a range of flow rates.

Results from the combined drill-bit stabilizer simulations were reported and design bottlenecks were identified for a legacy stabilizer model. New insights were gained for design modifications to address packoff. Simulation results show that the particles follow the flow path created by the slanted blades of the drill bit initially and then begin a swirling motion before passing through the stabilizer slots. The new design has a larger flow by area, and it straightens the rotating flow and hence offers faster evacuation of cuttings. The flow profile becomes more uniformly distributed and prevents any clustering of particles, thereby significantly reducing non-productive time (NPT) and improving tripability of the bottomhole assembly (BHA) in oil fields.

This study provides insight into stabilizer design concepts and the stabilizer’s location as it is combined with a drill bit. The integrated simulation approach adopted here enables operators to predict the motion of formation cuttings using a simpler particle model in a larger system and helps prevent drillstring packoff.
Simulation of Perforation Cleanup Dynamics and the Effect of the Direction of Gravity
Authors: Craddock G. G. , Haggerty Dennis
Published: April 2016

The understanding of perforation tunnel-flow dynamics in the presence of gravity or orientation is an important consideration. This work examines the flow dynamics after a perforation, both numerically and analytically. It presents CTH simulations of a perforation tunnel created by a shaped charge and the subsequent initial flow into that tunnel. CTH is a shock hydrodynamic code that can simulate the initial dynamics of flow driven by shocks. The longer-term stability of the flow into the perforation tunnel is further analyzed in terms of external influences, including the orientation with respect to the gravitational field. A stability analysis of the various types of instabilities present at interfaces of flow in a tunnel is performed. Simulation results for different charges indicate that the flow enters at different locations in the tunnel. This behavior is also expected to depend on the fluids present, the tunnel they create, and the type of rock. This paper also presents the temporal dynamics from CTH of the flow at different locations along the tunnel, along with a discussion of turning these flow results into predictive models for tunnel formation. The simulation results are then used as inputs into the analytic calculation. Various types of drag are considered, based on laminar and turbulent flow. In the latter case, the geometry of the rough surface and, consequently, the type of rock, plays a critical role in the flow. Results of the stability analysis can be shown to be influenced by the direction of gravity, for example. These instabilities can then influence the drag along the tunnel walls and subsequent cleanup. Consequently, when a cleanup test is performed in a flow facility that can rotate, such as an unconsolidated formation pressure vessel, the perforation tunnel geometry will be influenced by gravity. Suggestions are made to compensate for the gravitational influence on the flow, which can be translated into downhole performance enhancement.
Experimental and Simulation Study of Water Shutoff in Fractured Systems Using Microgels
Authors: Goudarzi Ali , Alhuraishawy Ali , Taksaudom Pongpak , Sepehrnoori Kamy , Bai Baojun , Imqam Abdulmohsin , Delshad Mojdeh
Published: April 2016

Conformance control has long been a compelling subject in improving waterflood oil recovery. By blocking the areas previously swept by water, subsequently injected water is allowed to access the remaining unswept portions of the reservoir and thereby increase the ultimate oil recovery. One technique that has recently received a great deal of attention in achieving the so-called "in-depth water shut-off' is preformed gel injection. However, processing and predicting the performance of these gels in complex petroleum reservoirs is extremely challenging. As target reservoirs for gel treatments are mainly those with fractures or ultra-high permeability streaks, the ability to model the propagation of gels through a fractured reservoir was considered as a new challenge for this research study.

The primary objectives of this work are to conduct laboratory work to understand the transport and propagation of microgel through fractures and develop conformance control schemes using a reservoir simulator to help in screening oil reservoir targets for effective particle gel applications to improve sweep efficiency and reduce the water production. Fractured experiments using transparent apparatus were performed to observe gel transport in matrix and fractures. The same set up was used to observe the effects of gel strength, gel particle size, and fracture size on gel transport. Numerical simulation of fluid-flow in fractured reservoirs can be computationally difficult and time consuming due to the large contrast between matrix and fracture permeabilities and the extremely small fracture apertures and the need for using unstructured gridding. In this work, a model that accurately represents the complex reservoir features, chemical properties, and displacement mechanisms is developed.

The five-spot transparent fracture experiments allowed us to identify the transport mechanisms of microgels through fractures-conduits and also the control variables. With an integration of comprehensive gel transport modules and a novel Embedded Discrete Fracture Modeling (EDFM), gel rheological and transport properties of shear thinning viscosity, adsorption, resistance factors, and residual resistance factor, using multiple sets of fractures with dip angles and orientations were captured. The models were validated against lab measurements and implemented into a reservoir simulator called UTGEL.

The mechanistic models and numerical tool developed will help to select future conformance control candidates for a given field and to optimize the gel chemistry and treatment.
Monitoring Production Well Testing Facilities Using Statistical Analysis
Authors: Brady Jerry L. , Kelley Timothy F. , Mehdizadeh Parviz , Starck Jennifer
Published: April 2016

There are over 50 well test facilities operated by BPXA on the North Slope of Alaska. The test facilities provide production measurement for 100s of producing wells that produce 100,000s of barrels per day. Well tests are a critical surveillance method for production optimization and reservoir performance monitoring of oil and gas fields. The quality of well tests directly impacts production operations, allocation, well workover activities, and capital investment decisions.

A cost efficient method to determine the quality of well testing operations is to use well test repeatability statistics. Observing well test data over periods of time provides the ability to identify anomalies in well operations and metering performance. This paper will discuss the details of an algorithm that was developed to determine the repeatability of well testing for all BP-operated North Slope well test facilities. This algorithm identifies and filters outlier well tests due to operational changes. Remaining well tests are then treated statistically to determine measurement performance.

A web application was developed to allow viewing, sorting, and analysis of well test repeatability statistical data by operational personnel. This application is used to rank well test facilities and wells with high deviations in gross fluid, gas rates, watercut, and oil rates. Examples of the application with actual field data are provided in the paper. Access to this data allows for improved business decision making, identification of problematic well test facilities, and prioritization of repairs and upgrades to equipment.
Drilling Engineering and Formation Evaluation: An Integrated Approach to Improve Real Time Drilling Optimization
Authors: Webb Jerry , Roze Erwan , Jarret Cameron , Le Roux Stephane , Mejia Camilo
Published: April 2016

In the current market climate, the industry is in a time squeeze and it is crucial for future value generation to reduce the well construction time and cost. Drilling Optimization practices have helped to increase drilling efficiency while reducing the likelihood of downhole failures. To see this effort further, an adequate engineering plan to design the operation strategy, along with the understanding of the geological challenges, assists in establishing a more robust real-time optimization program.

Real-time drilling optimization helps to improve drilling performance by providing early warning detection of downhole drilling events, maximum allowable deviation of planned vs. actual hydraulics and torque & drag measurements, and finding the "sweet spot" by use of drilling parameters. These processes can then further be optimized by the integration of pre-job engineering and formation evaluation measurements. Pre-job engineering seeks to ensure the BHA is able to resist vibration- related events, while the drillstring and bit are selectively examined for optimal hydraulics and resistance to torque and drag related issues. The pre-job engineering also considers ways to improve the rig’s overall efficiency, by eliminating invisible lost time while both in and out of hole. New generation of logging while drilling measurements help to provide reliable prediction of pore pressure for early warning of circulation problems, collapse events, lost circulation, blowout, and kicks. This process involves a depth-by-depth correlation between actual borehole lithology and pre-modeled unconfined / confined compressive strength (UCS/CCS). Optimized mechanical specific energy is evaluated using drilling parameters such as torque, RPM and ROP. The resulting two curves are then defined by calculating the value of MSE/CCS-UCS fraction to derive a drilling efficiency indicator. By correlating these curves, the drilling optimization team can identify geological formations that have the optimum correlation then compute the efficiency indicator for the interval, using it as baseline for drilling each hole section. This workflow guides the operations to make necessary real time adjustments to mitigate potential problems.

The workflow demonstrates the integration from the pre-job engineering design to the automation of the real time integrated evaluation, along with the accuracy of the new generation of Logging While Drilling technologies as a cost-effective solution to mitigate non-productive time and optimize drilling rates through the implementation of a solid drilling optimization program during the execution of ERD, offshore and unconventional projects.
Using Data To Create Foresight And Create Value From Volume
Authors: Snøtun Håkon
Published: April 2016

With the recent downturn in oil price, more of the fields in the arctic seem less financially viable and many projects have been postponed, or altogether abandoned. In an industry where companies are unable to change the market price and cost becomes the main differentiator, projects in the arctic have added worries because of an inhospitable climate, lack of infrastructure and severe environmental concerns. This means that companies have to plan better, but also plan differently in the arctic in order to stay competitive.

All planning should be data driven with a focus on learning from past experiences and projects, but how one handles data determines how much value can be extracted from volume, and how much insight and foresight one can expect. We have found that there are four main obstacles to using data effectively. Firstly, it can be hard to find the correct data, but even more importantly, it can be hard to determine what data is missing. By some estimates, geologists use 60% of their time looking for data and less than 20% looking for oil. Secondly, even though a lot of data is sometimes available, the data might not be accessible, and a lot of time is lost in planning from converting esoteric formats, different units of measure and a plethora of curve values. The third obstacle to use data is that the context for the data might be missing, which is even more important in the arctic, because it might be hard to determine if experiences obtained in one area can be transferred to arctic projects. Finally, data is often aggregated before the planning stage it might hard because of time constraints to investigate whether anomalies in the data is caused by error in the data or outliers that can add risk or cost to the project.

We will show how efficient use of Big Data techniques and statistical analysis can mediate the effects mentioned above, and how normalization and standardization of data can allow users to spend their time interpreting data. Although the use of data does not eliminate risk, it can help manage it by identifying which risks should be focused on, but also identify where the project moves into uncharted territory in terms of equipment, location, rig or other factors.
Field Testing and Validation of a Mechanical Alternative to Radial Jet Drilling for Improving Recovery in Mature Oil Wells
Authors: Balch Robert S. , Ruan Tongjun , Savage Mark , Harvard Jeff
Published: April 2016

Short radius laterals, where a drilling tool is able to make a right turn in a cased wellbore and then penetrate some distance out into a formation, is an attractive technology for enhanced oil recovery for both existing and new field developments. Lateral holes with different geometries can penetrate untapped compartments, thin or by-passed pay, less permeable oil zones that cannot be sufficiently drained by conventional processes, and extend the effective radius of a well while reducing skin effects. A commonly referenced technology is radial jet drilling, where a specialized shoe is deployed in the well, a casing cutter cuts a hole through the pipe, and then a nozzle with high-pressure cutting jets is deployed on a hose at the end of coiled tubing. The technology has yet to become common in the United States, despite tens of thousands of candidate wells that could benefit from such a restimulation. Problems with jet drilling systems include: uncertainty in distance and direction of emplaced laterals; low available power to front-facing cutting jets, as most of the power has to be directed to rear-facing jets to keep the nozzle on the formation; and difficulties cutting hard formations and when encountering hard clasts.

The objective of this study was to evaluate a newly developed technology for production enhancement from low-permeability reserves that utilizes a purely mechanical drilling string deployed on coiled tubing that is able to make a right-angle turn in a wellbore and drill a ~1.5 in. diameter lateral 30 ft or more into a reservoir. To study the technology, two wells were selected and stimulated.

A simulation study for one of the field test sites, Millman field, a Grayburg/San Andres field in the Permian Basin, New Mexico, allowed a sensitivity study for optimization of lateral emplacements, optimal number of laterals per level, and allowed prediction of the impact of the recompletions. The prediction of lateral efficiency showed that the four emplaced laterals gave the best overall efficiency for enhancing oil production with 28.5% predicted incremental production in previously stimulated zones, and a 33.3% increase for previously unstimulated zones. Diagnostic techniques for monitoring lateral direction and placement based on small, chip-based gyroscope and accelerometer chips were developed and field-tested, verifying lateral emplacement during the field tests. The first test well saw ~40% increase in oil rate with emplacement of 12 laterals in three intervals. The second test well saw a 47% increase in production after 15 laterals targeted a previously untapped zone.

This paper presents, discusses, and validates the drilling technology, the simulation models and results, the sensor development, and field-testing of those three technologies at two wells, with the emplacement of 27 total laterals with lengths of up to 32 ft.
Effective Extraction of High Viscosity and Low API Gravity Hydrocarbon Resources With Solvent-Steam Processes
Authors: Hascakir Berna
Published: April 2016

Extraction of unconventional resources is vital to meet future hydrocarbon demand. However, the effective extraction of these unconventional resources cannot be accomplished by the application of conventional technologies. This study summarizes different combination of different Enhanced Oil Recovery (EOR) methods to recover effectively the low API gravity and high viscosity crudes to find the main factors affecting the EOR performances most. Several steam flooding, steam assisted gravity drainage, and solvent aided-steam processes (SA-SP) (both with asphaltene solvent and non-solvents) were tested on heavy, extra-heavy, and bitumen resources. Carbon dioxide, propane, n-hexane, and toluene were tested as solvents. While carbon dioxide, propane, and n-hexane are asphaltene non-solvents, toluene is asphaltene solvent. The process performances were discussed in terms of cumulative oil recovery and produced oil quality. Produced oil qualities were compared according to their asphaltene, clay, and water contents. Asphaltene content directly correlates to the water and clay contents of the produced oil samples. As the asphaltene content of produced oil increases while the water content increases, the clay content decreases. The worst produced oil quality was obtained by SAGD and toluene-SAGD. The experiments conducted with the asphaltenes insoluble solvents (carbon dioxide, propane, and n-hexane) produced the highest quality oil with low water content and high deasphalted oil content.
The Effect of Clay and Salinity on Asphaltene Stability
Authors: Demir A. Birkan , Bilgesu H. Ilkin , Hascakir Berna
Published: April 2016

Destabilized asphaltenes cause serious problems by precipitating in the reservoir pores which reduces the oil flow by decreasing the reservoir porosity and permeability significantly. This study investigates the impact of clays and salinity on the stability of asphaltenes for five different crude oil samples. First, both n-pentane and n-heptane insoluble fractions of five crude oils were examined under microscope after the interaction with water, brine, and porous media. The porous media was prepared with clay only, sand only, or sand-clay mixture. A monovalent (NaCl) and a divalent (CaCl2) salts at 0.2% and 4% concentrations were used to prepare brine samples. The systematic microscopic imaging conducted on asphaltenes show that both n-pentane and n-heptane asphaltenes are getting dispersed in water phase. However, this dispersion is hampered with the existence of ions in water and this impact increases with the increase in brine concentration. Nevertheless, the destabilization of asphaltenes is more pronounced with the presence of clays. Because the destabilized asphaltenes are precipitated in porous media, asphaltenes precipitation impacts the wettability of porous media. Hence, the wettability of oil-water-rock and oil-brine-rock systems was determined through water-air contact angle measurements. The pseudo reservoir rock-oil-water/brine systems were prepared by keeping constant the weight of each component in the system for five crude oil samples. Reservoir rocks were prepared by mixing sand and clay. The brine was prepared either with NaCl or with CaCl2. The impact of salt concentration on wettability was tested for both 0.2% and 4% brine solutions. It has been observed that the asphaltenes fraction has an important role on wettability determination, however, the interaction of asphaltenes with deasphalted oil is the main contributor which defines the wettability of the system. Thus, our systematic analyses on asphaltenes should be extended and similar analyses should be conducted on the deasphalted oil fractions.
Polymer-Enhanced Foam PEF Injection Technique to Enhance the Oil Recovery for the Post Polymer-Flooding Reservoir
Authors: Dong Xiaohu , Liu Huiqing , Hou Jirui , Liu Guohua , Chen Zhangxin
Published: April 2016

Polymer flooding process is one of the most commonly-used EOR techniques for the waterflooded light-oil reservoirs. The further development after polymer flooding process is currently challenging the EOR techniques. Using the methods of physical simulation and numerical simulation, the feasibility of polymer-enhanced foam (PEF) injection process in post polymer-flooding reservoir is performed in this paper. Through the introduction of a concept of average foam-composite-index (FCI), an experimentally based screening criteria for PEF is proposed. And, the influence of polymer concentration on the plugging-effect of PEF is also experimentally investigated. After that, the parallel experiments of PEF injection and conventional foam injection are conducted. Then, based on the geostatistics data of an actual oil reservoir, a Lorentz-Monte-Carlo (LMC) algorithm is proposed to establish the heterogeneous geological models with different interlayer and plane permeability-variation-coefficients. Thus, the sensitivity of reservoir heterogeneity on the recovery performance of PEF injection is numerically analyzed, and the implementation plan of PEF injection is also optimized through an orthogonal test.

Experimental results indicate the plugging effect of PEF is significantly superior to the conventional foam. The optimal polymer concentration is 1500mg/L, and the injection of PEF could effectively enhance the oil recovery by about 17.1%. The improving effect of enhanced foam on oil recovery in heterogeneous reservoir is much more significant than that in the homogeneous reservoir. As the reservoir heterogeneity increases, the ultimate recovery factor increases. For the rhythm reservoir, the reverse rhythm reservoir with weak plane-heterogeneity and week interlayer heterogeneity could yield a better recovery performance. The optimal implementation plan of PEF injection process are that the slug size is 0.06PV, injection rate is 50t/d, gas/liquid ratio is 1:1, foamer solution is 0.5wt%, and polymer solution is 0.6wt%. This investigation sheds some important insights for the enhanced oil recovery (EOR) process of post polymer-flooding reservoir. It could be used as a tool for the successful design of PEF injection process during the high water-cut stage of post polymer-flooding reservoir.
Predicting the Effects of Acid Gas on Enhanced Oil Recovery in Hydrocarbon Gas Injection
Authors: Lv Sanbo , Liao Xinwei , Chen Hao , Chen Zhiming , Lv Xianwei , Zhou Xiaojin
Published: April 2016

Hydrocarbon gas injection is one of the major EOR methods. Hydrocarbon gas has some similar properties with the oil in reservoir, which has no damage to the formation. In addition, there is a beneficial mass transfer between hydrocarbon gas and crude oil, when achieving miscibility, the residual oil saturation where the area is affected by hydrocarbon gas is very low. The effects of the components of hydrocarbon gas as well as its impurities on enhanced oil recovery have been researched. However, in some fields, injected gas is from the produced gas with large amounts of acid gas. The corresponding EOR effects of hydrocarbon gas with high acid gas content are rarely mentioned in the literatures. Thus it is necessary to study it when hydrocarbon gas with acid gas is injected.

In this paper, acid gas consisting two common components (78.11% of H2S and 21.89% of CO2 respectively) is studied. The oil sample from typical block in K oil reservoir is selected to investigate the EOR effects of hydrocarbon gas with the above acid gas. The slim-tube experiments are performed with different percentages of acid gas in injected gas at different displacement pressures. The acid gas percentages are respectively 0%, 10%, 20%, 30%, 40%, 50%. The experimental procedure is that firstly the slim tube is saturated with oil, then it is displaced by hydrocarbon gas with one certain percentage of acid gas at constant temperature and displacement pressure. The ultimate oil recovery which is also considered to be the displacement efficiency is obtained after injecting 1.2 pore volumes of gas or when there is no oil production. Similarly, the experiments at different pressures are also conducted.

The experimental results show that under the same temperature, oil composition and gas composition, the displacement efficiency increases as the displacement pressure increases. However, displacement efficiency is no longer increasing when displacement pressure increases to one certain value. This pressure point, that is to say, is minimum miscibility pressure (MMP). It means, when the pressure is higher than MMP, the effects of displacement pressure on the oil recovery would not be significant. The experimental results also indicate that under the same temperature, oil composition and displacement pressure, displacement efficiency increases as the percentage of acid gas in the injected gas increases.

From the work here, MMP can be predicted. The effects of acid gas on enhanced oil recovery can also be estimated. In the oil field, all the results can be for reference in hydrocarbon gas injection with high acid gas content. In a word, this work is very meaningful, which provides a new perspective on enhancing oil recovery as well as cutting the pollution of acid gas. It is a win-win work.
Increasing Performance of Multilateral Wells Using Oil Fingerprinting
Authors: Jensen M. D. , Werner M. R. , McCaffrey M. A. , Dahl J. E.
Published: April 2016

In multilateral wells, several distinct processes including sand production, mechanical failure, and pattern depletion can cause a decrease in overall well performance over time. Within a lateral, sand can fall out from the production stream and form sand bridges that obstruct production from that lateral. In addition, sand co-produced with oil from shallower laterals can settle through the production stream to obstruct the entry to a deeper lateral. However, a decrease in production cannot be assumed to be due to obstructions formed by co-produced sand, since a variety of completely different processes can also reduce production. It is critical to know the cause of decreased production from a well, since which method is used to reverse the decrease in production very much depends on the cause of the decrease.

Geochemical techniques can be used to quantitatively determine the contribution of each of several zones to a commingled oil (or gas) stream. This technique costs less than 1-2% of the cost of production logging. One particularly useful application of this technique is using oil fingerprinting to identify sanded-out intervals for fill cleanout (FCO)

In brief, production allocation is achieved by identifying chemical differences between end-member oils (single-zone samples collected from each of the zones being commingled). Parameters reflecting those compositional differences are then measured in the commingled oil. Those data are then used to mathematically express the composition of the commingled oil in terms of contributions from the respective end-member oils. That result is achieved using a linear algebra manipulation of the concentrations of 150-250 compounds naturally occurring in the end member oils and the commingled oils.

In the current study, we show three examples where this approach was used to identify a sanded out interval in each of three wells. Once the sanded-out interval was identified, an appropriate FCO operation could be conducted. This approach resulted in increased production of 200 BOPD, 500 BOPD, and 400 BOPD in the three respective wells. For those wells, the cost of the geochemical analysis was less than the value of 1 hr of increased oil production.
Unlocking the Potential of Monterey Shale Resource: An Analysis of Geological Characteristics, Completion Techniques, and Production Behaviors
Authors: Saini D. , Wright J. , Mantas M. , Mezei T. , Gomes C. , Shetty S. , Sirajuddin M.
Published: April 2016

Over the last thirty years, technology used to produce hydrocarbons has grown exponentially. With the optimization and combination of technologies such as horizontal drilling and hydraulic fracturing, the ability to produce low-permeability or tight hydrocarbon-bearing rocks (shale formations) which were once deemed economically impractical has now become a reality. However, these technologies which have made hydrocarbon production from unconventional reservoir possible have not been implemented in California's Monterey Shale Formation for its wide scale exploitation. Also, due to the relatively short time period of these technological advancements, there seems to be limited research that provides a comprehensive comparison of these three major U.S. analogous shale plays (i.e. Bakken, Eagle Ford, and Monterey) for gaining better understanding on their potential use in future exploitation of Monterey Formation.

First, using publically available data, a comparison of key geological characteristics, completion techniques, and production behaviors of Bakken, Eagle Ford, and Monterey shale plays is presented. Monterey shale is very young and geologically heterogeneous compared to Eagle Ford and Bakken but holds significantly more reserves. Compared to Bakken and Eagle Ford, oil viscosity in Monterey shale is significantly higher and one can also notice that Monterey oil production has declined over the years. Monterey shale has a field dependent completion (pattern spacing and fracturing stage) strategy.

Second, the similar analysis is expended to three Monterey specific oil fields (M, N, and R) that are located in the San Joaquin basin (SJB) of California. A detailed diagnosis of the production behaviors of both the horizontal hydraulically fractured and horizontal non-fractured wells present in the R Field shows that actually non-fractured horizontal wells are more productive which reinforce the needs of a new completion as well as new enhanced recovery strategies that could assist in future development of California's Monterey shale resource while complying with the toughest hydraulic fracturing regulations in the nation.

Though water use per hydraulic fracturing job is relatively low, nearly all fracturing water use in California is in regions of extremely high water stress. The potential use of oilfield-produced water for preparing fracturing fluid formulations can also assist industry in unlocking the potential of Monterey shale without putting burden on precious fresh water resources of the region.
The Effects of Faults on Induced Seismicity Potential During Water Disposal and Hydraulic Fracturing
Authors: Umholtz N. , Ouenes A.
Published: April 2016

A predictive geomechanical model of induced seismic events across many Oklahoma counties is presented—the potential of this validated workflow to address numerous concerns with recent earthquakes is demonstrated. A network of large scale faults can greatly alter the stress field, and consequently the potential of induced seismic events resulting from water injection. These effects are quantified using a geomechanical workflow that leads to the estimation of Induced Seismicity Potential (ISP). It appears that most of the recent earthquakes are clustered in high ISP areas which could be found near but also away from critically stressed faults that were the focus of most recent investigations. When considering the volumes of water injected, the low ISP areas seems to accept large volumes without causing any major earthquakes. In contrast, high ISP areas near Oklahoma City, seem to have many earthquakes despite the low volumes of injected water. In other words, the location of the water injection wells seems to be a critical factor impacting the inducement of earthquakes and reduction of water volumes alone may not reduce induced seismicity. The lack of earthquakes near very large injectors located in low ISP areas seems to point to the need to restrict water injection only to low ISP areas which may reduce the number and magnitude of earthquakes. This predictive tool could assist regulators, oil and gas companies, and insurance companies in selecting areas with the lowest risk of induced seismicity while bolstering the social license to operate unconventional reservoirs.
Production Geology as a Tool for Monitoring Water Influx in a Compartmentalized California Monterey Fractured Reservoir
Authors: Zhao Xiaoxi , Ershaghi Iraj
Published: April 2016

This paper through a case study exemplifies the use of some common sense reservoir engineering methods using performance data in characterizing heterogeneity and compartmentalization in a complex fractured reservoir producing from the Monterey formation. The field is highly faulted and water influx has been a source of energy in this reservoir.

Guided by 2D-3D seismic interpretation, we have examined the merits of using performance data (oil rate, cumulative oil production, GOR and WOR) to characterize block to block communication as an important aspect in characterization of geological complexities in various compartments of the reservoir. Using performance data for a number of wells, we have made estimations about the historical rise of oil-water contact and its relationship to the water influx, communication among blocks, block capacities and future production potential. Monitoring of water ratios has indicated that there are differences in the level of water entry depending on individual blocks properties. GOR's have indicated different stages of depletion. Our study shows that the performance data can provide insight and further assist in geological characterization.
Water Blocking Caused by Fracturing Fluid Leakage in Mixed-Wet Unconventional Tight Reservoirs
Authors: Kong Bing , Chen Shengnan
Published: April 2016

It has been recognized that, water blocking caused by water-based fracturing fluid leakage is one of the major reasons for well productivity reduction in hydraulic fractured tight formations. Mixed-wettability is broadly existing in tight/shale hydrocarbon reservoirs and it has profound impact on water blocking. In this paper, formation damage caused by water-based fracturing fluid leak-off in mixed-wet tight oil/gas reservoirs is studied. Sensitivity of water blocking on rock wettability, capillarity and permeability is analyzed and early time production is optimized to remediate the damage of formation productivity caused by water blocking.

The sensitivity of the water blocking behavior is studied by using a multi-phase dual-wettability model. Results from the reservoir simulations demonstrated that a well-resting period varying from one to twelve months can significantly affect early productivity rate and reduce flow-back of fracturing fluid in mixed-wet reservoirs. The damage to productivity due to water blocking will be reduced along production in a single-wet reservoir, however this damage is irreversible in a mixed-wet formation. The results also indicate that minimizing water leak-off in the formation is crucial in both single wet and mixed wet reservoirs.

The mixed wettability of an unconventional tight reservoir is considered in this study, and a multi-phase dual-wettability model is applied to study the water blocking in such formation. The results of this study can provide meaningful guide for hydraulic fracturing and early production in mixed-wet unconventional tight reservoirs.
Unlocking Gas From a Methane Hydrate Reservoir – Barrow, Alaska
Authors: Youngmun N. C. , Stokes P. J. , Walsh T. P.
Published: April 2016

Executive Summary

Drilling and testing of the East Barrow Gas Field (EBGF) began in 1974. Over the next sixteen years, eight vertical production wells were drilled. In 1988, initial gas reserves were estimated to be 6.2 BCF OGIP with 5.7 BCF recoverable. Despite these early predictions, the field has produced approximately 9.1 BCF of natural gas and the reservoir has maintained pressure at ~ 935 psia, which suggests there are still untapped gas resources within the EBGF.

It was initially believed that continual re-pressurization of the reservoir was caused by an active water drive. However, no significant water has been produced, even from down dip producers. Reservoir modeling was performed to better understand reservoir drive mechanisms and to predict future reservoir behavior. Recent modeling and reservoir simulation strongly suggest that gas hydrate dissociation and negligible water influx is responsible for the constant re-pressurization within the EBGF. Recent drilling and production shows that gas production from the EBGF depressurizes the reservoir and raises the base of the gas hydrate stability zone, unlocking free gas from the hydrate bearing reservoir rock. This is a significant finding, and validates the presumption of commercial gas production from a hydrate resource. This paper summarizes the technical studies conducted to understand the reservoir behavior and the evidence supporting ongoing dissociation and production of methane hydrates from the EBGF.
Application of Dynamic Allocation Factors for Waterflood and EOR Performance Management
Authors: McElhaney Kevin , Jemison Jenny , Jhaveri Bharat
Published: April 2016

Field-wide displacement and EOR floods become increasingly difficult to monitor and analyze as a system matures. Dynamic effects such as slug size, well work, pressure management, and concurrent injection can all influence performance in a way that is not captured using geometric static allocation factors. By calculating dynamic allocation factors for each time step, the dynamics of field operations can be attributed to the corresponding wells. Proper allocations can influence field operating strategies by using past performance to predict future returns in the field.

Building on the concept presented in 2006 by Bharat Jhaveri, the dynamic allocation factors are calculated by an iterative process that includes all injection and production data in a time-step. Production-centered allocation factors are dependent on the surrounding volumes of injection supporting the well. Injector-centered allocation factors are dependent on the surrounding production volumes that the injector supports. Interactions are monitored and tracked using a matrix style catalog for each time step. Total injection allocation factors can then be modified for EOR application by taking into account the delayed production enhancing effects caused by solvent injection.

Dynamic allocation factor analysis was completed using real field data on a system with two injectors and fourteen producers. These injectors injected both water and miscible gas on regular WAG cycles. The results of the analysis were used to evaluate waterflood and EOR performance. For the waterflood, maturity, recovery, and pressure management are the metrics required to evaluate field performance. For the EOR performance, maturity, recovery, and utilization are used to optimize oil recovery. Dynamic allocation factors were able to capture lag time in injector-producer interactions, highlight non-interactions between wells owing to geological influence, and changes in reservoir streamlines during periods of shut-in wells.

Traditional well allocation factors between injectors and producers are assigned based on the geometry of that pattern. This method provides a static, unchanging view of the reservoir system, regardless of the operational dynamics. A dynamic allocation factor is derived iteratively to accurately depict reservoir interactions through time. Field management can be improved using this view of how fluids in the reservoir have historically interacted. Injection targets, infill drilling, and changes to injector conformance can all be optimized through analysis employing dynamic allocation factors.
Core to Pore Scale Visual Analyis of Mixing Process in the Presence of Interface Between Heavy-Oil and Solvent
Authors: Hassan Saleh F. , Babadagli Tayfun
Published: April 2016

Solvent injection, which is the only alternative to thermal methods to reduce the viscosity of heavy-oil, requires an effective solvent distribution in the reservoir to achieve the maximum oil-solvent contact. The dilution process, however, becomes slower as oil gets heavier. In this case, an initial interface exists between oil and -liquid or gas- solvent (similar to ultralow immiscible fluids cases). In case of heterogeneous reservoirs (fractured carbonates or wormholed oil sands), the diffusive mixing between the solvent in the fractures/wormholes and matrix oil requires longer contact times. Hence, an initial interface between the solvent and oil may exist and, depending on the wettability conditions, the existence of water and oil/solvent type, capillary imbibition (liquid solvent) or drainage (gas solvent) transfer into the matrix may take place. Intrusion of oil by capillary imbibition accelerates oil recovery reducing the time to get the oil and solvent contacted in order for the dilution (mixing) process to start.

To investigate this phenomenon and perform a parametric analysis, an experimental design was developed focusing on analyzing the oil-solvent mixing zone mechanisms. A wide range of oil types (50cp to 100,000cp) and solvents (heptane and decane) were used. Experiments were performed on oil saturated 3 × 7 cm 2-D glass (core scale) and glass capillary tubes by soaking them into solvent under static conditions. To identify the mixing process (by color gradient) and distinguish the phases, advanced illumination and photographic techniques were applied using UV light and coloring the solvent.

The followed experimental approach employed visual models at core and pore scale levels and successfully displayed the existence of both capillary imbibition and diffusion mechanisms in a solvent heavy-oil system. To what extent capillary imbibition could occur and assist in the recovery by miscible interaction was clarified for different oil, solvent, and wettability conditions. The results revealed that the solvent injection process might be enhanced by other mechanisms (imbibition or drainage) in heterogeneous reservoirs, which is usually neglected in modeling studies.

Initial capillary imbibition took place if the glass surface was more solvent-wet than the original oil. Diffusive mixing followed by convective mixing occurred. Time periods corresponding to different recovery mechanisms were identified for different wettabilities and oil viscosities.
Avoiding Flowline Plugging: A Deposition Velocity Model and Stability Map
Authors: Bbosa Ben , DelleCase Emmanuel , Volk Michael , Ozbayoglu Evren
Published: April 2016

Transportation of solids in form of slurries has become one of the most important unit operations in industries across several disciplines. In fact, the need is more pronounced in industries that are very important for human survival such as food processing, pharmaceuticals and energy (coal, oil and gas). A lot of work has been done in the past 30 years in understanding the factors affecting the deposition velocity of solids in slurries. Experimental observation and theoretical predictions pointed to mixture velocity and solid/fluid properties especially rheology of the resulting slurry to be the most important factors that dramatically affect particle motion and patterning.

This paper presents a critical deposition velocity model and a "stability flow map" for complex rheology slurries. The critical deposition model utilizes a more robust generalized 2-parameter rheology model to account for any given slurry rheology. The "stability flow map" demarcates the different flow patterns that may be observed at different mixture velocity and rheology. On this map, the homogeneous slurries are predicted at low rheology and high mixture velocity whereas heterogeneous slurries (with a concentration gradient) predicted at high rheology (yield stress effects).

Sensitivity analysis was conducted on critical Reynolds number, particle density, carrier fluid density, generalized flow behavior index, and pipe diameter. It was observed that increase in shear thinning behavior, particle density, pipe diameter, and particle diameter led to a decrease in the laminar region and an increased unstable region. The model showed good performance when tested on glass and stainless steel beads test data available in open literature. The model was tested on hydrate slurries generated with additives at The University of Tulsa and the flow regime predictions were in good agreement with observations.

Preliminary simulation with this map may help engineers select flowline size and carrier fluid rheology for a given type of solid particle.