bluuebunny/crossref_metadata_2025 huggingface dataset:
In-Situ Visualization of Multidimensional Imbibition in Dual Porosity Carbonates
Authors: Alshehri Amar J. , Kovscek Anthony R.
Published: October 2014

Well-performing waterflood usually recovers 50% of oil in place. This number is even lower in fractured carbonates where the injected water selectively channels through fractures towards producers leaving much of the oil trapped in the matrix. To mitigate the low recovery, one option is to reduce fracture uptake by increasing the viscosity of the injected fluids using polymers or foam. Another option, which is the objective of this work, is to inject surfactant solutions to reduce capillary effects responsible for trapping oil and allow gravity to segregate oil by buoyancy. Analysis of gravity and capillary forces suggests that such segregation is achievable in the laboratory provided that cores are moderately long and oriented vertically. Besides investigating gravity effects on oil recovery, the effect of surfactant flood mode (secondary flood mode and tertiary flood mode) on the ultimate recovery (UR) was also investigated.

To investigate the predictions of this analysis, core-flood experiments are conducted using carbonate cores and monitored by an X-ray computed tomography (CT) scanner to quantify fluid saturation history in situ. Novel aspects of this work include cores that are oriented both horizontally and vertically to maximize gravitational effects as well as a special core holder that mimics aspects of fractured systems using whole core. This paper discusses the contrast in experimental results in vertical and horizontal orientation with and without surfactant.

To study gravity effect, the used surfactant reduced interfacial tension (IFT) from 40 mN/m to 3 mN/m. For this mode of recovery, ultralow IFT is not preferred because some capillary action is needed to aid injectant transport into the matrix. The vertical experiment showed that gravity has the potential of improving oil recovery at low IFT. Although the IFT reduction was not large (one order of magnitude reduction), recovery factor (RF) increased by more than 4% of original oil in place (OOIP) leading to an incremental recovery factor (IRF) of more than 7%. Another surfactant was used to study the flood mode effect; the used surfactant reduced IFT from 40 mN/m to 0.001 mN/m (ultralow IFT). In this study, two experiments were conducted: a tertiary surfactant flood experiment and a secondary surfactant flood experiment. The secondary flood experiment showed an increase of 7% in the ultimate recovery factor (URF) compared to the tertiary flood experiment.

This work highlights the importance of gravity at low IFT in terms of mobilizing trapped oil and also the impact of flood mode on UR. Moreover, this work emphasizes on the use of surfactant solutions as a method of enhancing oil recovery in fractured resources not necessarily due to wettability alteration but mainly due to gravity effects. Results are presented primarily as 3-dimensional (3D) reconstructions of in-situ oil and water phase saturation.
Standard Operating Procedures (SOPs) as a Catalyst for Culture Change
Authors: Howard Duhon , Jorge Garduño
Published: October 2014

Standard Operating Procedures (SOPs) for oil and gas production facilities are typically written by teams of subject matter experts including at least process engineers and experienced operators. The team is tasked with identifying the most effective ways to operate the facility (based on safety, environmental protection and economic measures). Operating the facility consistently in accordance with the SOPs should yield considerable benefits.

Yet, despite their obvious importance, often relatively little effort goes into SOP development and use.

SOPs are frequently developed late in the project, after the design is completed and construction is well underway. They may be used for little other than operator training. Following the initial facility startup, they may even end up on a shelf collecting dust. In this environment SOPs have little influence on either the design or the operation of the facility.

SOPs however could be so much more. They can be an integral part of the design process and a catalyst for culture change in the industry. Generated early enough they can be a powerful tool for finding and correcting operability issues in the design. Improving the design in this manner should yield a facility that is easier to operate and inherently safer. Effective SOPs that are actually used in the field could have a significant further impact on process safety.

This paper suggests methods for generating SOPs that accomplish the dual goals of improved design and improved, safer operation. The approach involves writing preliminary procedures (high-level and mid-level) much earlier in the design process and maturing the procedures along with the design. Another important feature is that the final procedures are simpler, easier to use, easier to scan and less likely to be misinterpreted.

This paper will also provide background information to understand how we have arrived at this method for procedure writing as well as provide several key examples of learnings from previous projects.
Lessons Learned From an Eagle Ford Shale Completion Evaluation.
Authors: Centurion Sergio , Junca-Laplace Jean-Philippe , Cade Randall , Presley Greg
Published: October 2014

A multi-disciplinary study combining reservoir, completion and production information enables understanding of how to optimize completion strategies and enhance well productivity. This study focuses on the Eagle Ford shale formation in northern LaSalle County. A data-driven approach is followed by first identifying general trends in completion designs from around 50 horizontal wells.

The study aims to identify parameters that have the most influence on production in the Eagle Ford shale formation. Multivariate analysis was implemented to determine which completion parameters are the main production drivers. Special attention was given to dataset filtering and processing.

Comparing well productivity across an entire play like the Eagle Ford can be challenging because reservoir characteristics change and operators employ various field development and completion design strategies. The study minimizes variations in geology and completion schemes by focusing on a 6-mile diameter area. Variation in completion design is also minimized by only considering newly completed wells with similar hydraulic treatment designs.

In addition to production trends, the use of stress profiles, rock properties and microseismic clouds are investigated to constrain modeling of fracture length and height.
Fracturing Fluid Effects on Young's Modulus and Embedment in the Niobrara Formation
Authors: Corapcioglu H. , Miskimins J. L. , Prasad M.
Published: October 2014

Shale plays and the evolving technologies of horizontal drilling and hydraulic fracturing are driving the petroleum industry in many regions. Due to their low permeability, hydraulic fracturing is necessary for economic production in these shale systems. The success of these reservoirs is dependent on optimized hydraulic fracturing designs, and requires an understanding of the mechanical properties of these reservoirs.

One of these properties, Young's modulus, can weaken the formation if it is reduced. This weakening of the formation can, in turn, lead to; increased proppant embedment into the fracture face and a subsequent loss of conductivity. In low permeability shale reservoirs, the conductivity achieved through fracturing is just as critical as in other formations, thus making proppant embedment an issue that needs to be fully understood. This paper focused on how different fracturing fluids impacted the Young's modulus of the Niobrara shale, a major producing formation in the states of Colorado and Wyoming, and how this change affects proppant embedment and conductivity with certain proppants.

Nanoindentation technology was used to determine Young's modulus changes in Niobrara core samples after they were saturated for 30 days in certain fracturing fluids, and after they were heated under temperature (180°F) for five days. Treated samples were then subjected to high pressure (3030 psi) with selected proppants, simulating a fracture to test the proppant embedment profiles using scanning acoustic microscope (SAM) and profilometer measurements.

The experimental results showed that Young's modulus decreased with fluid exposure regardless of the fracturing fluid type and also increased (rebounded) after a certain saturation time. The magnitude of decrease in Young's modulus values was dependent on fluid type and saturation time. In one extreme case, (when KCl+friction reducer fluid was used as treatment fluid for 30 days) Young's modulus decreased by approximately 80%. The Young's modulus reduction is believed to be mainly caused by a weakening of the calcite minerals. Higher reductions experienced by KCl based fluids could be due to a detrimental chemical reaction between KCl and calcite minerals. Results also showed proppant embedment and crushing are inevitable under the tested circumstances and are dependent on distributed stress on the contact points as well as proppant type and fluid exposure.
Study on the Application of Wellhead Compression in Offshore Facilities
Authors: González Díez N. , Slot H. , Smeulers J. P.
Published: October 2014

As gas fields mature and their reservoir pressure declines, gas production rates are reduced. Addressing other associated issues with low reservoir pressures, such as liquid loading, eventually leads to higher operational costs. In order to facilitate the production of mature gas fields, a possible solution is installing compression. By introducing compression, the well-head pressure is reduced, thereby allowing larger gas flow rates. Wellhead compression (WHC) is the solution by which a compressor acts locally over one or a number of wells. In this way, the backpressure for a number of selected wells can be reduced. A case study for an offshore field in the North Sea is used to investigate the feasibility and the best possible arrangement of WHC in a satellite platform.

Three possible engineering solution layouts at the satellite platform have been identified, to be checked against three design cases. Each solution is assessed on the basis of power requirements and equipment needed. Potential reliability issues are addressed. Potential products available in the market that be used have been highlighted, especially on the compressor and driver side. Statistical figures about the reliability of compressors and drivers are distilled from an offshore Oil & Gas Reliability database.

It is concluded that WHC on a satellite offshore platform can be best addressed with a multiphase pump, provided that sufficient liquid is available or necessary engineering is interesting enough to be undertaken. If that is not the case, a solution with a vertical-separator/slug-catcher and an oil-flooded screw compressor is encouraged. The best available driver for this arrangement appears to be a gas engine on the basis of plot space and reported reliability figures.

The present work represents a first step towards the application of well-head compression at offshore facilities. In addition to the conclusions, potential pitfalls are identified. Several uncertainties are addressed that would require further research. First, reliability issues associated to possible emulsions occurring in a screw compressor when water and condensate and/or oil are put in contact; second, reliability statistics regarding gas engines and screw compressors are in contrast with O&G operators' experience.
Enhancements in Fraction Measurements and Flow Modeling for Multiphase Flowmeters
Authors: Chazal D. , Fiore M. , Jolivet G. , Lupeau A. , Toussaint C. , Fournier B. , Hollaender F.
Published: October 2014

Multiphase flowmeters (MPFMs) have been used since the early 1990's in the oil and gas industry and have gained acceptance in many environments. They have been considered the primary metering option for a wide range of applications - from heavy oil to wet gas. The combination of operational benefits, measurement robustness, demonstrable accuracy, and auditability has improved their status from new, unproven technology to that of the premium mainstream metering option.

With more than a decade of experience acquired using a combination venturi and gamma-ray multiphase flowmeters, further gains in measurement quality and operational robustness have been achieved. We will illustrate how enhancements in fraction measurements using multi-energy gamma ray attenuation and a more comprehensive analysis of the gamma-ray spectrum have been developed and implemented to provide better measurement accuracy and stability, leading to enhanced performances in multiphase flow measurements.

Another area of improvement that has been pursued is in the field of modeling of multiphase flows through a venturi. Historically, single-phase flow equations have been used, being adapted to multiphase flows by semi-empirical means to account for their complexity. While such models have proven robust for most standard applications, they can reach some limitations in particular conditions. We will present how a more dynamic model that considers the nature of the flow has led to improved accuracy of multiphase flow measurements.

We present the scientific basis for the new enhancements as well as illustrate the accuracy gains achieved based on hundreds of flow loop test points, ultimately leading to the quantification of the accuracy gains obtained through those technological improvements.
Formulation of Porous Medium Momentum Equations Using Variational Principles
Authors: Kubota Leonardo
Published: October 2014

This work shows that the powerful tools of Analytical Mechanics are suitable to describing the physics of single-phase fluid flow in porous media. We present a derivation of porous media momentum equations (also referred to as generalized Darcy's Law) using variational principles. More precisely, we shall rely on the Lagrangian formulation of Mechanics – an analytical approach - instead of the traditional, geometrical and vector-based Newtonian approach to derive the differential equations governing the dynamics of the fluid velocity in the porous medium. The problem of fluid flow in porous media provides an interesting setting where one can apply the most general form of Lagrange Equations – derived recently by Pesce (2003) - which is capable of treating particle systems whose mass depends explicitly on time, generalized coordinates and velocities. If such dependence is overlooked, then the derivation of generalized Darcy's Law via the classical form of Lagrange Equations will produce erroneous results.
Comparison of Methods for Stochastic Multiphase Flow Rate Estimation
Authors: Zangl Georg , Hermann Roland , Schweiger Christian
Published: October 2014

Even though flow rates of oil, gas and water are the most important parameters of any hydrocarbon exploitation project, only a minor number of wells are permanently connected to a multiphase flow meter (MFM). Production well testing through a test separator is by far the most common practice to measure flow rates. This method comes with the restriction that only one well at a time can be tested, leading to sparse measurements over the production history of a well.

In addition, operating conditions of the test separator can differ from flow line conditions and results in a discrepancy of flow line rates versus test rates. To account for this effect the well-test results have to be reconciled, usually backwards from the sales/export meter to each well.

More and more wells are equipped with SCADA systems, measuring wellhead parameters in real-time. Data driven technologies are able to learn the correlation between well test flow rates and wellhead measurements, so that they can calculate production rates at any time between well tests. Data driven methods are fast, so that they can be applied in real time and are therefore sometimes called virtual meters. They can overcome the difference of well test and flow line conditions and predict fairly accurate rates.

This paper compares a very simple regression method (MLR), a classification method (random forest) and a back-propagation neural network (ANN). All three methods are trained on real-time data from step rate well tests obtained from three wells. A blind test is performed on all three trained models to compare the predictability of each method.

As the calculation time of these data driven methods is very short, they have been embedded in a stochastic loop to account for the variation of the acquired real time parameters during the tests. A standard deviation is calculated from the stochastic simulation. The standard deviation is not only a good measure of the predicting capability of each method, but also embraces all operational variations of flow conditions during testing. This leads to a better estimation of the most likely flow rate at current conditions.
Advanced Petrophysical Surveillance Improves the Understanding of Well Behavior in Unconventional Reservoirs
Authors: Ansari Rafay , Yadav Himanshu , Thiruvenkatanathan Pradyumna , Zett Adrian , Spain David , Gysen Alain
Published: October 2014

Multi-stage hydraulic fracturing in horizontal wells is an essential stimulation technique to enhance production and economics in unconventional tight gas sands in North America. However, one of the challenges that still remains is to understand and quantify the efficiency of each perforation cluster in order to optimize completions. Operators have used various production logging technologies in an attempt to understand completion efficiency. Even then, these low rate horizontal wells with unstable flow conditions and fluid segregation provide a challenging environment for production logging, and even the use of different tools / software provides no definitive answer. Absence of direct comparison between logging tools renders it difficult to assess the suitability of a particular tool in a given downhole environment. A field trial was thus conducted to acquire and compare the log data using two very different instruments, an array based logging tool and a downhole distributed fiber optic (DFO) with distributed temperature and acoustic sensing (DTS / DAS) capability.

A multiple array tool, consisting of multiple spinner and resistance arrays, was deployed downhole via tractor into a well that had been on production for approximately three months. Multiple up/down passes were made at different speeds in both lateral and vertical sections to assist with spinner calibration. Following this, a retrievable DFO system (with both DTS/DAS) was run in the same wellbore and data was collected continuously for two days. A memory temperature tool was also added to the DFO toolstring to ensure post-acquisition temperature calibration and depth correction.

This paper highlights the advantages and disadvantages of both logging techniques and suggests ways to improve flow profiling in low rate horizontal wells. It also shows that overall comparison of the data from the two tools looks good, with some differences resulting from the different nature of these measurements. This paper further shows how other surveillance data including radioactive proppant and chemical tracers, open-hole logs, cement bond logs, and geomechanical data in these horizontal wells can be used to complement the production logging results and provide insights to optimize future completions.
Attenuation-Based Quantitative Cement Bond Index with LWD Sonic: A Novel Approach Applicable to all Casing and Cement Cases
Authors: Pistre V. , Kinoshita T. , Blyth M. , Saenz E.
Published: October 2014

In recent years, there has been a strong interest in evaluating casing to cement bond with an LWD sonic tool. In 2013, we presented an amplitude-based approach, similar to what is used with wireline tools with its potential and limitations. During this study, extensive modeling was conducted and verified with real data sets to show that the amplitude of the signal propagating inside the tool collar can sometimes become larger than the signal traveling along the casing, which limits the applicability of the first-arrival amplitude for bonding evaluation in thin casings and heavy cements.

From observations made during this investigation, it was noted that when the collar arrival was affecting the casing amplitude signal, the apparent attenuation rate obtained in these conditions anti-correlated with the attenuation measured by a wireline tool. This surprising observation triggered a review of the physics of sonic signal propagation in cased hole and the development of a new formulation of the bond index when an LWD tool is used for the measurement.

This new approach uses the attenuation of the casing and tool collar signal along an array of receivers from an LWD sonic tool, which extends the quantitative cement evaluation to the full range of bond index in all types of casing and cements if the ambient noise level permits. This new methodology uses the knowledge of the propagation inside the tool collar, which is well characterized for new LWD tools.

This different methodology does not require any tool calibration, mud attenuation compensation, or the presence of a free-pipe section for in-situ normalization of the measurements. It is therefore free of user interaction and can be implemented in the downhole tool processor for real-time answers while drilling the cement. This provides a very early knowledge of the casing-to-cement-bond integrity before drilling through the casing shoe, thereby reducing drilling risks. The approach was validated with real examples that showed how the new approach overcomes the limitations of the amplitude-based process formerly used.
A Methodology to Determine Economic Viability for Early Phase Projects in Under-appraised Fields with Ambiguous Data
Authors: Saeedi Alireza , Villela Felipe , Bungo Elise , Kaygorodtsev Evgeny , Zuluaga Elizabeth , Wang Ben
Published: October 2014

Long interpretation time after drilling appraisal wells results in evaluating uneconomic development options further than they should be considered. This study presents how a project team developed a structured approach to evaluation of the results of an appraisal well in order to minimize turnaround time in making decisions on economic viability of a project after completion of the appraisal well.

A project team was created to define the opportunity and evaluate the economic viability of the project. The team developed a structured approach to facilitate rapid evaluation of the appraisal well results against an established project economic viability framework. The developed methodology consists of entering a preliminary production forecast and facilities and drilling costs into an economic model. A varying EUR (Expected Ultimate Recovery) multiplier was then utilized to determine the minimum required EUR to make the project economic based on DPI (Discounted Profitability Index) threshold. Different development scenarios in terms of facilities design and recovery mechanism were evaluated in this study. Once the minimum required EUR was obtained from the economic model, the team calculated the minimum appraisal well OHIP (original Hydrocarbon In Place) volume needed for an economic opportunity assuming a drainage area based on regional benchmarking study. The analysis also included a procedure to adjust the calculations based on net pay thickness in the appraisal well location relative to average field net pay thickness. The values obtained from this exercise were then used as a signpost for the appraisal well and was checked against the data collected from the well. This allowed for a quick economic viability analysis of different development scenarios and identification of scenarios that needed to move to the next phase for more detailed analysis.
Matrix Permittivity Measurements for Rock Powders
Authors: Seleznev Nikita V. , Fellah Kamilla , Phillips John , Zulkipli Siti Najmi , Fournie Bastien
Published: October 2014

Formation water content is one of the key petrophysical quantities provided by dielectric logging. However, to determine water content from formation permittivity measurements the rock matrix permittivity must be known. Uncertainty in the rock matrix permittivity values translates into uncertainty in the water content estimate, which is especially important in low-porosity formations or complex lithologies. Matrix permittivity values are not well known for a number of minerals and can also vary for the same type of mineral in different formations. Thus, a laboratory methodology for the accurate determination of matrix permittivity at dielectric logging frequencies is required to facilitate accurate log interpretation.

Matrix permittivity values can be measured on solid plugs (Seleznev et al., 2011). However, the plug-based methodology can be challenging in very low-permeability or unconventional reservoirs because of difficulties with plug drying. In addition, it is not readily applicable to unconsolidated formations. Finally, it may be impossible to cut solid plugs due to limited availability of rock material. Matrix permittivity measurements made on rock powders are capable of addressing all of these issues.

We introduce a methodology for laboratory measurements of matrix permittivity on rock powders at 1 GHz. The methodology is based on conducting dielectric measurements on mixtures of rock powders and liquids with variable permittivities in a dielectric resonator. The permittivity of the rock matrix is inverted from a series of measurements obtained on pure liquids and powder-liquid mixtures. The methodology was benchmarked on a collection of samples representing common oilfield lithologies with matrix permittivity values between 4.6 and 8.6. The reference matrix permittivity values were first measured on solid plugs. Then the plugs were crushed into powders and the matrix permittivity values were determined on powders following the proposed methodology. The values obtained on powders matched the ones measured on solid plugs within 0.2 dielectric units resulting in accuracies better than 1% for the water-filled porosity and better than 1000 ppm for water salinity.

This new methodology was applied to a number of core samples from a carbonate reservoir, offshore Sarawak where dielectric logging had been performed along with conventional core analysis. The resulting measured matrix permittivity values were then used to interpret the dielectric log measurement. Results showed a better estimation of water filled porosity and of the textural MN parameter than would have resulted from using ‘chartbook’ values of matrix permittivity. A consistent and optimized interpretation was obtained in porosities ranging from 5% to more than 30%.
A New Approach to Modeling Production Decline in Unconventional Formations
Authors: Ogunyomi B. A. , Dong S. , La N. , Lake L. W. , Kabir C. S.
Published: October 2014

Most decline curve methods have two main limitations; the model parameters as a rule are not functions of reservoir parameters and may yield unrealistic (nonphysical) values of expected ultimate recovery (EUR) because boundary-dominated flow may not develop in unconventional reservoirs. Over the the past few years, several empirical models have emerged to address the second limitation, but they are challenged by the time to transition from infinite-acting flow period to the boundary-dominated flow. In this study, we performed statistical and model-based analysis of production data from hydraulically fractured horizontal oil wells and present a method to mitigate some of the limitations highlighted above.

The production data were carefully analyzed to identify the flow regimes and understand the overall decline behavior. Following this step, we performed model-based analysis using the parallel-flow model (sum of exponential terms), and the logistic-growth model. After the model-based analysis, the model parameters were analyzed statistically and cross plotted against available reservoir and well completion parameters. Based on the conclusion from the crossplots and statistical analysis, we used design of experiments (DoE) and numerical-reservoir simulations to develop functions that relate the model parameters and reservoir/well completion properties.

Results from this work indicate that the production characteristics from these wells are highly variable. In addition, the parallel-flow model indicates that there are at least two to three different time domains in the production behavior and that they are not the result of operational changes, such as well shut-in or operating pressure changes at the surface. All the models used in this study provide very good fits to the data and all provide realistic estimates of EUR. The cross-plots of model parameters and some reservoir/well completion properties indicate that there is some relationship between them, which we developed using DoE and flow simulations. We have also shown how these models can be applied to obtain realistic estimates of EUR from early-time production data in unconventional oil reservoirs.
Unconventional Reservoir Geology of the Neuquén Basin Argentina
Authors: Barredo Silvia , Stinco Luis
Published: October 2014

The Neuquén Basin is one of the most important hydrocarbon producing basins of Argentina and is presently being explored and restudied because of its unconventional reservoirs rocks. Since the basin resulted from thermo-mechanical processes acting on a structured lithosphere a geodynamic analysis was needed for interpreting the regional distribution of its depositional sequences and their associated unconventional reservoirs. This basin corresponds to a continental rift developed during differential intraplate stresses derived from a backarc extension. Most of the border fault systems consist of reactivated structures whose attitude with respect to the extensional regime controlled the geometry of the basin. The infilling consists of clastic and pyroclastic rocks sourced from continental alluvial-fluvial environments during Triassic to Early Jurassic times to alternative marine-continental during most of the Jurassic to Cretaceous times. This evolution is consistent with troughs growing larger through time but being affected by recurrent extensional pulses during accelerated basin subsidence and or seal level change overlapped by compressional forces which resulted in a complex environmental relationship throughout the basin. Consequently, vertical and lateral facies variations are present in reservoir rocks along the basin which requires a detail analysis to proper model the petroleum systems. Especially because significant hydrocarbon source rocks of this basin, that can be produced as unconventional, like the highly known Vaca Muerta Formation. The aim of the present contribution is then to propose an integrated, geodynamic and tecnostratigraphic model to the Neuquén Basin which can improve the understanding of its geological evolution particularly considering that the estimated resources related to unconventional reservoirs are 455 TCF.
Steady-State Relative Permeability Measurements, Temperature Dependency and a Reservoir Diatomite Core Sample Evolution
Authors: Vega B. , Kovscek A. R.
Published: October 2014

Evaluation of thermal-recovery processes requires relative permeability functions, how such functions change with temperature, as well as the evolution of rock permeability and porosity as floods progress. There are significant challenges associated with estimating relative permeability, and its temperature dependence, from laboratory data including the accuracy of data and generalized assumptions in the interpretation technique. Direct measurements of relative permeability curves through the steady-state method are ideal and scarce, in particular for low-permeability systems. This study reports the results of a long-term study to measure the steady-state oil/water relative permeability as a function of temperature of a core sample from a low-permeability, siliceous shale, diatomite reservoir. All tests were isothermal, carried out at temperatures ranging from 45 to 230 °C (113 °F – 446 °F). In-situ phase saturation was monitored using an X-ray CT scanner. Results obtained show a systematic shift towards increased water wettability with increasing temperature. Dependence of endpoint phase saturation and relative permeability with temperature is apparent from these measurements thereby confirming the transition to water-wetness with increasing temperature previously derived from spontaneous imbibition experiments on previous diatomite samples. A post-mortem analysis of sample porosity distribution and rock quality reveals the evolution of additional petrophysical attributes as a result of two years of thermal flooding.
A One-Year Production Study between Cemented Multistage and Openhole Completion Technologies for Vertical Wells in the Permian Basin
Authors: Lohoefer Darrel , Keener Brett , Ezeldin Saiff , Snyder DJ
Published: October 2014

The Permian Basin is one of the top five resource plays in the United States and consists of a number of stacked pay zones. Two of these formations, the Wolfcamp shale and Bone Spring (together referred to as the Wolfbone), deliver a pay zone thickness from approximately 1,000 to 1,500 ft. They are made up of several different layers of organic rich shales, intermingled with sandstone and siltstone. Horizontal completions in the shales are just beginning and have yet to be proven; however, operators are successfully exploiting the reserves through vertical wells.

While a mature exploration area, the completion of the thick shale intervals is a new target formation. To date, two vertical completion methods have been utilized to gain access to hydrocarbons: openhole multistage systems (OHMS) and the conventional cemented liner, "plug and perf" (CLPP) method. This paper compares 1 year production results from 12 vertical wells in Reeves County, Texas completed with OHMS systems and 56 offset wells completed with the CLPP method. The system details, fracture methods used, as well as the cost and operational differences are discussed.

By comparing these two methods, this paper highlights OHMS as a long-term solution for operators completing vertical wells in stacked pay. The production, operation and cost comparisons of the two completion methods will provide theoretical and practical arguments to assist in designing a completion. The results of this study contribute to the technical conversation of how to economically produce a vertical well.
Multiphase Flow and Reactive Transport at the Pore Scale Using Lattice-Boltzmann Computer Simulations
Authors: Boek Edo S. , Zacharoudiou Ioannis , Gray Farrel , Shah Saurabh M. , Crawshaw John P. , Yang Jianhui
Published: October 2014

We describe the recent development of lattice-Boltzmann (LB) and particle tracing computer simulations to study flow and reactive transport in porous media. First, we have extended our codes to measure both flow and solute transport from LB calculations directly on pore space images obtained from micro-CT scanning. We consider rocks with increasing degree of heterogeneity: a bead pack, Bentheimer sandstone and Portland carbonate. A novel scheme is proposed to predict probability distributions for molecular displacements using the LB method to calculate both the flow field and solute dispersion. We find excellent agreement with PFG-NMR experiments and quantify the degree of heterogeneity by integrating over the stagnant peaks in the propagator distributions. Second, we validate our LB model for multi-phase flow by calculating capillary filling and capillary pressure in model porous media. Then we extend our models to realistic 3D pore space images and observe the calculated capillary pressure curve in Bentheimer sandstone to be in agreement with experiment. A new process based algorithm is introduced to determine the distribution of wetting and non-wetting phases in the pore space, as a starting point for relative permeability calculations. The Bentheimer relative permeability curves for both drainage and imbibtion are found to be in good agreement with experimental data. These LB simulations can be used for the prediction of multi-phase flow properties in pore space images; as potential element of Special Core AnaLysis (SCAL); and for Enhanced Oil Recovery (EOR) operations. Third, we introduce a GPU algorithm for large scale LB calculations, offering greatly enhanced computing performance in comparison with CPU calculations. Finally, we propose a new hybrid method to calculate reactive transport on pore space images. First, we calculate the flow field using LB and initialise tracer particles in the porous medium. Then we carry out particle advection using a 2nd order predictor-corrector scheme, particle diffusion using a random walk followed by reaction. We simulate the dissolution of a sphere under quiescent conditions in good agreement with the analytical solution. Then we calculate the dissolution of a cylinder in channel flow and observe preliminary agreement with experimental observations. This opens the way to calculating the dissolution of pore space images in direct comparison with micro-CT imaging experiments, for matrix acidizing and CCS operations. It is concluded that the LB method is a powerful tool for calculating flow and reactive transport directly on rock pore space images.
The Effect of Changing Fracture Compliance on Pressure Transient Behavior During Diagnostic Fracture Injection Tests
Authors: McClure Mark W. , Blyton Christopher A. , Jung Hojung , Sharma Mukul M.
Published: October 2014

Diagnostic Fracture Injection Tests (DFIT) are commonly interpreted with G-function derivative plots. In these plots, an upward deviation from linearity is generally attributed to fracture height recession or transverse storage. This interpretation neglects changing fracture compliance during closure. Results presented in this study show that in low permeability formations, an upward deviation of the G-function plot G*dP/dG is caused by a sharp reduction in fracture compliance due to closure. It is not necessary to invoke more complicated explanations such as height recession or transverse storage. The specific shape of the G*dP/dG curve is controlled by factors that affect fracture compliance before and after closure. These factors include the fracture height, fracture stiffness, and the residual aperture (which is affected by the microscopic and macroscopic roughness of the created hydraulic fracture). Wellbore storage broadens the post-closure peak in the G*dP/dG curve. A curve of G*dP/dG that constantly increases during the shut-in period may be caused by wellbore storage, rather than fracture tip extension. In higher permeability formations (with non-zero wellbore storage), the effect of fracture compliance is less important. As a result, changing fracture compliance during closure does not have a significant effect on the pressure transient plots, and closure decreases the rate of pressure decline because it reduces the rate at which fluid can leak off into the matrix. In all cases, as long as a single planar fracture has formed, the best pick for the minimum principal stress is at the deviation from linearity on the G*dP/dG plot, whether or not this departure is concave up or concave down. Closure picks via a tangent to near the peak in G*dP/dG (as is commonly performed) may significantly underestimate the minimum principal stress. These picks should be confirmed with other measurements, such as a subsequent injection period or a pump-in flow-back test. The fact that an extremely sharp upward trend in G*dP/dG is generally not observed in DFIT tests suggests that the actual geometry of the created fracture is rougher and more complex than is typically assumed by standard models.
Modeling Flow in Nanoporous, Membrane Reservoirs and Interpretation of Coupled Fluxes
Authors: Geren F. , Firincioglu T. , Karacaer C. , Ozkan E. , Ozgen C.
Published: October 2014

The average pore size in unconventional, tight-oil reservoirs is estimated to be less than 100 nm. At this pore size, Darcy flow is no longer the dominating flow mechanism and a combination of diffusive flows determines the flow characteristics. Concentration driven self-diffusion has been well known and included in the flow and transport models in porous media. However, when the sizes of the pores and pore-throats decrease down to the size of the hydrocarbon molecules, the porous medium acts like a semi-permeable membrane, and the size of the pore openings dictates the direction of transport between adjacent pores. Accordingly, characterization of flow and transport in tight unconventional plays requires understanding of their membrane properties. This paper first highlights the membrane properties of nanoporous, unconventional reservoirs and then discusses how filtration effects can be incorporated into the models of transport in nanoporous media within the coupled flux concept. The effect of filtration on black-oil simulation data is also demonstrated.
A New Mechanism of Formation Damage in Sandstone Matrix Acidizing Caused by Apatite; A Phosphate Cementing Material
Authors: Sakipour A. , Nasr-El-Din H. A.
Published: October 2014

Mineralogy is a key controlling factor in sandstone matrix acidizing treatments. Quartz, feldspars, calcite, dolomite, and different cementing materials are present in sandstone formations. It is crucial to be aware of the mineralogy in order to design acid treatments. Authigenic apatite, (Ca5(PO4)3(OH, F, Cl)2), is a cementing material in fluvial sandstone formations. If apatite is present in the formation, it will cause precipitation during matrix acidizing. The objective of this paper is to discuss a new mechanism of formation damage caused by apatite during matrix acidizing.

Laboratory experiments were conducted on sandstone cores at 140 and 300°F. Different cores with different mineralogy were selected to investigate the effect of apatite on the results of the acid treatment. Scanning Electron Microscopy (SEM) and Energy-Dispersive X-ray Spectroscopy (EDS) were used to analyze the mineralogy of the cores and to confirm the presence of phosphorous in the core samples. Cores were first damaged using fresh water, then preflush (formic-HCl) and organic mud acid (formic-HF) were employed to remove the damage. The initial and final permeability of the core was measured to investigate the result of the acid treatment. Core effluent samples were collected during each experiment for further analysis. Inductively Coupled Plasma (ICP) was utilized to determine the concentration of key cations in the core effluent samples. The SEM/EDS techniques were used to identify the precipitation in the core effluent samples.

This study showed that the presence of phosphorous in the core samples caused more damage after acid treatment. The presence of phosphorous caused precipitation. The SEM/EDS tests detected phosphorous in the core sample. However, it was not detected in all spots of the core that were tested. This indicates that the phosphorous was not distributed homogenously throughout the cores. The analysis of the precipitation in the core effluent samples indicated that the presence of phosphorous in the core caused the precipitation of iron(III) phosphate (FePO4) and aluminum phosphate (AlPO4). The precipitation occurred in samples where the pH was greater than 4. In addition, the precipitation occurred at both 140 and 300°F. Conducting experiments on the cores that did not contain phosphorus resulted in no precipitation in the core effluent samples. The samples were clean and transparent. The permeability measurements confirmed that the precipitation in the core effluent samples affected the results of the matrix acidizing and caused damage. This paper provides detailed evidence of a new mechanism of formation damage due to the presence of apatite as a cementing material.
Frictional Pressure Losses of Slurries in Straight and Coiled Tubing – Part I: Model Statistical Analysis
Authors: Shaqlaih Ali S. , Kamel Ahmed H.
Published: October 2014

Hydraulic fracturing has increased immensely in recent years. An accurate prediction of frictional pressure losses of fracturing slurries is crucial for successful treatment and to avoid premature screen-out or even treatment failure. Scarce data and lack of theoretical basis of slurry flow, especially in coiled tubing has led to very limited number of correlations that are available to predict slurry frictional pressure losses. Yet, the accuracy of the available correlations is still questionable.

The current paper presents a statistical comparative analysis of the available frictional pressure losses correlations for slurry flow in straight and coiled tubing employing the recently introduced math modeling technique that gives weight for the models known as Akaike information criterion, AIC. With the help of AIC, the authors evaluated the available correlations to examine their accuracy. The results show that none of the available correlations can accurately predict friction pressure losses of slurries. The correlations show some reasonable accuracy within a very limited data range. However, they fail outside this range indicative of their poor applicability. AIC shows how much information is lost when using these correlations which can lead to erroneous results, and even job failure. This fact keeps the gates widely opened for more in-depth experimental, analytical, and theoretical analysis for better understanding of flow behavior of fracturing slurries aiming at developing a more realistic correlation to predict their frictional pressure losses. This paper represents the authors' first step toward developing such correlation, with the application of information theory and AIC.
Understanding Multi-Fractured Horizontal Marcellus Completions
Authors: Shelley Robert , Nejad Amir , Guliyev Nijat , Raleigh Michael , Matz David
Published: October 2014

This project was undertaken to evaluate well potential and completion effectiveness for hydraulically fractured horizontal Marcellus completions located in Susquehanna County, Pennsylvania. This paper summarizes a study of the response of the Marcellus shale to hydraulic fractures and identifies performance drivers. How effective are these completions? How would these wells produce if they were completed and fraced differently? What are the primary controllable production drivers? How significant is geology and reservoir characteristics on well production? This paper attempts to answer such questions. Identification of major performance drivers becomes important in the design and optimization of new completions. They are not just important in enhancing production response and ultimate recoverable reserves but also prove to be important economic factors in new completion design.

This study employs neural network (ANN) modeling techniques to develop a predictive model to identify performance drivers and evaluate completion effectiveness. Sensitivities performed on the predictive ANN model developed for this project, indicate that well to well variation in reservoir quality and geology has a dominate effect on Marcellus production. Issues such as fracture spacing, frac volume, perforation distribution, proppant amount and fluid volume also affect well production. A summary of completion and frac methodology for wells in this database and a ranking of controllable (Completion and Frac) and non-controllable (Reservoir and Geology) parameters that effect Marcellus production are included. This information will be useful to stake holders interested in identifying reservoir, completion and frac parameters affecting production from the Marcellus and other analogous shale.