bluuebunny/crossref_metadata_2025 huggingface dataset:
An IPIECA Oil and Gas Framework for Water Stewardship
Authors: Wyness A. J. , Fennessey K. D. , Buttini P.. , Thorne K.. , Romer R. F. , Ruck P. S.
Published: June 2014

Water is an essential element in the upstream and downstream operations of oil and gas companies. Yet water, particularly fresh water, is already a scarce resource in many parts of world and further constraints are predicted. Continuing the development and implementation of water stewardship practices across the oil and gas lifecycle is therefore considered an important component in a company’s sustainability strategy.

IPIECA, the global oil and gas industry association for environmental and social issues, has recently made significant strides in this arena to raise stakeholders and the industry’s awareness of water management issues. IPIECA has developed a water management framework which adopts the principles of water stewardship. Uptake and adoption of the framework should lead to recognition by internal and external stakeholders that the oil and gas inudsty is proactively and collectively managing the issues related to sustainable water use and acting as stewards of this valuable resource.

The IPIECA water management framework outlines a series of industry guidelines, tools and initiatives providing a comprehensive approach through the full lifecycle of oil and gas development and production. The framework builds upon the systematic approach which is adopted by IPIECA to manage water risk – ‘global->local->guidance’ (SPE 157544). This approach includes the use of the IPIECA Global Water Tool for Oil and Gas and the Global Environmental Management Initiative (GEMI) Local Water Tool for Oil and Gas to help business better understand both the global and local level water risk from which specific guidance is then developed.

The World Water Forum Target 2.3.6 which was identified at the 6th World Water Forum in Marseilles in 2012, to "drive responsible water management in oil & gas exploration and production" is aligned with the IPIECA Water Management Framework. Work on this target is being led by IPIECA with support from the International Association of Oil and Gas Producers (OGP). The development of the IPIECA framework should support and improve the sector’s water management practices and approaches.
Results From Anular Injection in Heavy and Extra Heavy Oil Wells Producing With Rod Pumping in the Samaria Field: A Field Test
Authors: Jiménez H. M. , Naranjo J. E. , Herrera R. Pérez
Published: June 2014

Tertiary reservoirs of southern Mexico are mature reservoirs, producing mostly heavy oil since the sixties. Nowadays a massification program of steam injection it is being developed to produce extra heavy oil. Due to the low pressure and the oil properties, from 6° to 24° API of the tertiary reservoirs, an artificial lift system it is required, the most used are: gas lift, sucker rod pumping and progressive cavity pumps. The quantity of sucker rod pumping wells represents 52 % of the active wells of the field, which produce oils with viscosities from 100 to 90,000 cP, at a mean well head temperature of 33° Celsius. Wells producing high viscosity oil (less mobility) with sucker rod pumping system, have shown low efficiency problems mainly due to the rod string floating and fluid pound at the pump, as a consequence, flow improver injection was implemented. In order to determine the flow improver effect over the system, a field test was conducted.

The tests were conducted injecting flow improver by the annular at different concentrations and registering well parameters (well head pressure, temperature, liquid level, polished rod load, dynamometric cards, oil rate), also, the viscosity changes of the produced oil was evaluated. During the test, two different flow improver injection protocols were followed, one of them was established to inject from low to high doses, the other one, to dose form high to low doses.

The results obtained demonstrate that at the actual operation conditions, mechanical shaking is required to turn the hydrocarbon-flow improver mix homogeneous, reaching
Modification of the Kozeny-Carman Equation To Quantify Formation Damage by Fines in Clean, Unconsolidated Porous Media
Authors: Krauss Eva D. , Mays David C.
Published: June 2014

Estimating formation permeability as a function of porosity, grain size, and the quantity and structure of fines is important in reservoir engineering. One can use the Kozeny-Carman equation to estimate the permeability of clean, unconsolidated media as a function of porosity and grain size, but it does not account for the quantity and structure of deposited fines. This study shows how incorporating of the volume of fines and a dimensionless bulk factor into the Kozeny-Carman equation can be used to model how the quantity and structure of deposited fines control permeability. Several experimental studies from the literature are analyzed, representing a range of fines (type and diameter), porous media, fluids, and Darcy velocity. These studies indicate that, when other variables are held constant, experiments conducted at a higher Darcy velocity result in less plugging. For each experiment, a dimensionless bulk factor in the Kozeny-Carman equation was fitted, with use of the root-mean-square method, to best match the experimental data. Fitted values of the bulk factor were then correlated with the Péclet number to investigate how the structure of fines, quantified by the bulk factor, depends on the characteristics of the porous media, the depositing colloids, and the Darcy velocity. Larger bulk factors are observed at a lower Péclet number, when diffusive transport dominates, which could result from more-dendritic deposits. Smaller bulk factors are observed at higher Péclet numbers, when advective transport dominates, which could result from deposits that are more compact. By understanding how the bulk factor, and, therefore, the extent of permeability reduction, depends on the Péclet number, one can optimize pumping schemes. The primary application of this work is to optimize well-pumping rates to prevent or manage plugging that results from the deposition of fines in initially clean, unconsolidated porous media, including both geologic formations and gravelpacks used for sand control.
A New and Practical Oil-Characterization Method for Thermal Projects: Application to Belridge Diatomite Steamflood
Authors: Zhang L.. , Pieterson R.. , Dindoruk B.. , Stoffels P.. , Fan Y..
Published: June 2014

Most of the oil-characterization approaches for thermal recovery are designed for heavy oils at moderate temperatures, in which oil can be represented in very simplistic ways (such as “gas” and “oil”). However, when oil is exposed to very high steam temperatures (i.e., 550°F), and/or the oil is lighter than the classical range defined for heavy oils and is exposed to a wide spectrum of thermal effects, such as distillation of the lighter ends, the conventional methods of representing the interaction of steam and the in-situ fluids are not accurate. In many cases, we have to first evaluate the quality of the data, and then represent the average behavior with a single most likely fluid model per reservoir segment (plus other scenarios, as needed) to simulate the production performance. There is a need to develop a streamlined approach to bring such data into industrial simulators in a practical way.

In this study, we have developed a fit-for-purpose approach to generate a consistent pressure/volume/temperature (PVT) model over the whole reservoir, reflecting both pressure and temperature changes through the entire oil accumulation. The model represents the oil viscosity for a wide spectrum of temperatures, from reservoir temperature to steam temperature (thermal-process range). A systematic lumping scheme enables conversion of the characterized PVT model for numerical simulators with the minimal number of pseudocomponents while still capturing the essence of thermal physics. To our knowledge, there is no systematic study of this nature available in the literature.

We have tested this approach in the Belridge diatomite steamdrive project. The study confirmed that steamflood incremental oil production in a light-oil reservoir is sensitive to the component-lumping scheme because of distillation of the lighter ends. We also found that a five-component PVT model, representing the physics in “fit-for-purpose” dynamic simulation, best compromises between minimal number of components and physical description of the light-oil behavior.
Estimation of Production Rates With Transient Well-Flow Modeling and the Auxiliary Particle Filter
Authors: Lorentzen Rolf J. , Stordal Andreas S. , Nævdal Geir , Karlsen Hans A. , Skaug Hans J.
Published: June 2014

In the current work, we combine a detailed transient multiphase well-flow model and modern estimation techniques into a tool for better representation of flow rates in petroleum wellbores (influx or outflux). Accurate flow rates lead to better well control and reservoir management, which again are important for the improved recovery of oil from existing petroleum fields.

To achieve this, it is possible to use the fact that smart wells with multiple zones and laterals are more common, and they may be equipped with permanent instrumentation and control. Many wells have pressure and temperature gauges in each zone, or even distributed temperature sensing with high spatial resolution. Today, accurate flow-rate measurements or accurate estimates for each zone are lacking, and existing tools are often limited to steady-state models with no uncertainty analysis.

The estimation technique applied here is the auxiliary-sequential-importance-resampling (ASIR) filter, which has the advantage of being more-robust and -reliable than the traditional particle filter (PF). The ASIR filter is used to tune the output of specific stochastic models of the flow rates. To perform this tuning, we have chosen a jump-type model for the flow rates. These kinds of models are popular within areas such as econometrics and finance. More specifically, the model implies that the flow-rate process changes structure governed by an underlying Markov jump process. Using this type of model makes us capable of capturing not only smooth transitions but also more-abrupt changes of the flow rates.

We have applied the methodology on two synthetic studies (involving multiple zones and fluids), and our case studies clearly demonstrate the feasibility of the automatic identification of reservoir flow-rate distribution from wellbore measurements.
Multiphase Flow of Water, Oil and Natural Gas Through Vertical Flow Strings
Authors: Tek M. Rasin
Published: June 2014

Introduction

Multiphase flow through vertical pipe is encountered in many engineering installations. In petroleum, chemical process, nuclear engineering and many other industries, problems associated with simultaneous flow of two or more phases through vertical pipe have been of interest for a long time. This interest has increased considerably during recent years due to applications to new processes in petroleum production and refining and to problems of steam generation and heat removal from nuclear reactors. One prominent example of vertical two-phase flow is provided by the gas-lift process where oil, water and gas flow simultaneously. If the pressure profile in a gas-lift well can be predicted within reasonable accuracy, it would be possible to get good estimates of the power required to lift the oil, the optimum depth, the pressure and the rate at which to inject gas. Furthermore, the effect of production rate and tubing sizes on these quantities can be evaluated before any design decisions are made on the installation and operation of the flow string.

The majority of experimental work available in the literature deals with two-component systems where individual phase flow rates in and out of the pipe remain constant. The general problem of prediction of pressure drops in multiphase flow systems is very complicated. The co-existence of numerous flow patterns of widely different geometry and mechanism, conditions of surface instability and the nature of force fields acting upon the system are among the major difficulties commonly encountered. The classical approach of fluid dynamics which would be based upon the formulation and solution of Navier-Stokes equations has been found by many investigators completely devoid of any hope of success -- not only because of inherent nonlinearities but also because of insurmountable analytical difficulties standing in the way of setting up the boundary conditions. The presence and effect of interfacial forces on multiphase flow systems further complicate the theoretical approach. For these reasons, many investigators choose to adopt semi-empirical if not purely empirical approaches in order to obtain solutions of engineering utility.
Analysis and Countermeasures on the Efficiency of the Pumping Wells System in the Old Oil-field
Authors: Suling Wang , Tiejun Zhou , Yang Gao , Ying Long , Siyuan Huang , Yuning Wang
Published: June 2014

In China, some old oil fields into the late stage of development, the wellbore fluid become complexity, and the production and the pump efficiency gradually decline, which lead to an increase in production costs. According to the statistics, the efficiency of 36.7% of the total wells are lower than 30%, By analyzing the main reason for the low efficiency of the pump and combined the status of oil well production, statistical analysis on the impact of system efficiency under different working conditions and establish a corresponding model. The model mainly analyses the impact of stroke number, the stroke, the pump diameter, the submergence depth and gas content on pump efficiency. According to the well structural characteristics, a geometric model of the downhole rod system is established and the finite element model is generated by unit discrete. Considering the boundary conditions of the contact boundary of the sucker rod and tubing, the frictional resistance between the sucker rod and well fluid, the frictional resistance between the plunger and the pump barrel and the process of loading and unloading of the oil column, the numerical solution technology is adopted, which can reproduce the state of deformation of the rod string in a stroke, and gain the indicator diagram of the down hole pump and the efficiency of the system the down hole rod. Selecting the test wells of the oil production plant in Daqing Oilfield to check the model, the results show the error of pump displacement is 0.7% and the error of rod efficiency is 7.8%. On the basis of this analysis, the different stroke, pump speed, dynamic liquid level and pump diameter impact on the rod efficiency is analyzed. The calculation results show: the rod efficiency decreases with the increase of stroke and pump speed, the rod efficiency increases with the increase of fluid level and pump diameter and when the product of the stroke and stroke number is a fixed value, high speed and low stroke is beneficial to improve the efficiency of rod.
Real-Time Azimuthal Gamma and Resistivity LWD Data Used to Navigate Complex Unconventional Reservoir - Western US Land
Authors: Martin Stephen J. , Thomas Mark G. , Hammons Shane D. , Wilke Nate
Published: June 2014

The Denver-Julesburg Basin in northern Colorado is an unconventional hydrocarbon play utilizing horizontal wells to access several targets, known locally as benches, including the Niobrara B-Chalk. The need to navigate and optimally place completion packers in the unconventional play with complex, laminated rock structure and sub-seismic faulting is important to effectively stimulate productive rock. While bulk gamma is primarily used to correlate the formation, more advanced real-time LWD technology is proposed to navigate effectively and maintain the wellbore within the specific target chalk. A high resolution LWD electrical imaging tool is also employed to optimize the completion strategy and confirm real-time interpretations.

An azimuthal gamma ray image was used to determine formation bed dip and stratigraphic complexity along with two different resistivity measurements to correlate position within the reservoir. Thedata was transmitted in real-time to a remote geo-steering center where a Reservoir Navigation Engineer incorporated the data into the geological model and provided the operator with real-time steering recommendations for remaining within the zone of interest. Additionally, the data were used toidentify faults and interpret the fault-throw direction and distance.

The well was drilled with 85% of the lateral section placed in a 10-ft-thick target zone compared to less than 50% in offset wells navigating with gamma only. This was accomplished despite crossing over one sub-seismic fault and having relative formation dips varying from 88 to 92 degrees.

The improved net-to-gross was a result of the utilization of azimuthal gamma, multiple propagation resistivity, and the real- time Reservoir Navigation Service (RNS). The increased "in-zone" footage indicates this method provided a significant advantage over gamma-only measurements when navigating such complex and faulted formations. Post well, the high resolution LWD electrical image logs were used to confirm the faults and determine packer placement for optimal completionefficiency.
Detection of Symptoms for Revealing Causes Leading to Drilling Failures
Authors: Skalle Pål , Aamodt Agnar , Gundersen Odd Erik
Published: June 2014

When a diagnosis of a problem is known, the problem can usually be solved efficiently. This paper presents a method that helps reveal the most probable cause of a drilling-process failure immediately after occurrence. Normally, it takes some time to investigate and evaluate all available information before the correct cause can be determined. The method presented is targeted at reducing this time and at the same time improving the quality of the interpretation. The method relies on input parameters from the ongoing drilling process, parameters that behave irregularly and are referred to as symptoms or errors when the irregularity is severe. Recognized symptoms are used as input parameters in a knowledge-modeling method that relates symptoms to failures. The method was verified on the basis of historical drilling data, and its ability to point out the correct causes with high probability was demonstrated. Field testing the method is yet to be performed.
Gelled Emulsions of CO2-Water-Nanoparticles
Authors: AlOtaibi Fawaz M. , Kokal Sunil L. , Chang Yun C. , AlQahtani Jassi F. , AlAbdulwahab Amin M.
Published: June 2014

Enhanced oil recovery by CO2 injection is an effective method for recovering additional oil beyond waterflooding. In recent years it has garnered a lot of attention for two primary reasons: (a) the stable high price of oil and (b) environmental aspects of CO2 sequestration. Its use has been increasing steadily over the past few years. In many respects it is a win-win situation with CO2 sequestration and additional, incremental oil produced. However, the CO2-EOR process is handicapped, especially in thick reservoirs, by CO2 gravity override. Due to density differences between the injected CO2 and resident fluids in the reservoir, the lighter CO2 tends to rise to the top of the reservoir thereby bypassing some of the remaining oil. This results in poor sweep efficiency and conformance. Different techniques have been used to overcome the CO2 gravity override by either increasing its density, viscosity, or reducing its relative permeability. This paper investigates the use of gelling CO2-water emulsions, stabilized by silica nano-particles, to control the mobility of CO2.

The stability of nano-particles was first investigated using iso-octane (iC8) as a proxy for CO2. The stability of these emulsions, or foams, was investigated as a function of nano-particles concentration, type, hydrophilicity degree, and also as a function of iC8/water ratio. The silica nano-particles concentration ranged from 0.5 to 2 wt%, and iC8 phase volume ranged between 50 and 90%. Stability experiments were conducted at room temperature and up to 17 hours using both hydrophobic and hydrophilic colloidal silica nano-particles. Following the screening studies with iC8, rheological measurements were made using CO2 at 200°F and 1,800 psi at different (CO2/water) ratios and nano-particles concentrations. Compared to pure liquid CO2, high emulsion viscosities from 1.1 to nearly 2.5 cP were achieved. These values represent almost a 100-fold increase over pure sc-CO2 viscosity. Additionally, in some cases rigid gels were observed with time following emulsion generation. The CO2-water-nanoparticle emulsions were generally stable. This work provides the rheological results of the emulsion systems as a function of time, nano-particles concentration and CO2 phase volume. The high viscosity CO2/water emulsions have the capability to enhance CO2 mobility, act as a diverting agent during CO2-EOR, and improve sweep efficiency.
Evaluation of Downhole Oil/Water Separation in a Casing
Authors: Svedeman S. J. , Brady J. L.
Published: June 2014

Laboratory tests were conducted to evaluate the effectiveness of oil/water separation in a deviated well casing that is located below the perforation intervals.

Downhole water separation and reinjection is needed to reduce well operating costs associated with producing large amounts of water to the surface. In the casing separator, produced water flows downward from the well perforations with entrained oil buoyantly separated to the topside of the casing. A dip tube, running to the bottom of the casing, feeds a downhole pump that pumps the water into another level in the reservoir.

A test facility was constructed to test the casing separator performance at a variety of well inclination angles, production flow rates, water cuts, and reinjection water flow rates. At each operating condition, the amount of oil entrained in the reinjection water was measured to determine the maximum amount of water that could be separated and still provide "clean" water to the downhole pump. Tests were conducted over well inclination angles from 18° to 75°. The maximum water velocity in the casing separator, for clean water, varied from 0.2 ft/sec to 0.4 ft/sec.

The test results provided the information needed to determine how much water could be separated in the casing separator.

With the separator performance data, the economics of reinjecting water with a downhole pump could be evaluated.
A Modern Approach to Optimizing Underground Natural Gas Storage
Authors: Economides Michael J. , Wang Xiuli
Published: June 2014

Natural gas will emerge as the premier fuel of the world economy for two primary reasons: a surfeit of new and massive discoveries and substantial environmental benefits. Because of new and proliferating modes of transportation, natural gas will become fungible. This is likely to reduce large seasonal price fluctuations and especially it will eliminate price disparities, currently observed throughout the world.

Natural gas underground storage, mostly a North American practice, using depleted oil/gas reservoirs, water aquifers, or salt domes, will have to be expanded and enlisted almost everywhere.

We present here a series of new models for the physical management of gas storage facilities and the indicated injection and withdrawal schedules. Connected to the physical models are economic models that take into account natural gas price fluctuations. Optimum injection and/or withdrawal rates are determined weekly.

The model implementation starts at any time in the life of a storage reservoir with any amount of gas in storage. Then, taking into account gas price fluctuations, an injection/withdrawal schedule is determined to maximize profit and eliminate loss. The possible natural gas rates are not arbitrary but will be related to average rates already experienced in the field that are based on material balance, reservoir pressure and at the extremes, the abandonment pressure and the maximum allowable injection pressure.

We apply the models to entire US storage industry for two significant years, 2008 and 2012, compare and critique actual past injection and withdrawal history with the would-be optimum injection and withdrawal schedule that should be based upon gas price history. We show the disparity between the optimum schedules and what was actually followed. We also show considerable improvement in storage economics, compared to the actual history, if only the previous weekly prices were to be used as the gauge for injection/withdrawal.
Connate Water Saturation - Irreducible or Not: the Key to Reliable Hydraulic Rock Typing in Reservoirs Straddling Multiple Capillary Windows
Authors: Xu Chicheng , Torres-Verdín Carlos , Yang Qinshan , Diniz-Ferreira Elton Luiz
Published: June 2014

Irreducible water saturation is an important attribute to quantify reservoir petrophysical quality in terms of flow capacity. High in-situ capillary pressure causes connate water saturation in reservoir rocks to approach the irreducible stage, thereby providing a direct link between electrical and hydraulic conductivities. A new hydraulic rock typing method is developed by relating resistivity-saturation equations with core-calibrated Timur-Tixier's permeability model, both of which are expressions of porosity and irreducible water saturation in this special reservoir context. Petrophysical quantities equivalent to Leverett's reservoir quality index (RQI) and Amaefule's flow zone indicator (FZI) are derived from petrophysical analysis based solely on conventional logs, including gamma ray, neutron porosity, bulk density, and resistivity.

We test the new method on a deltaic gas reservoir from offshore Trinidad (Columbus Basin). In the field case, rock typing accuracy based on the new rock typing method is improved by 12% in terms of their contingency coefficients with core-based hydraulic rock types. We also discuss the limitations of the new method in detecting and ranking reservoir rock types in complex contexts of reservoir saturation-height. A new concept, referred to as capillary window, is developed to categorize the applicability of the new rock typing method. At extremely high capillary pressure, irreducible water saturation of different rock types is shown to have significant overlapping, thereby introducing large uncertainty in rock typing. Across capillary transition zones, methods to correct for the presence of free water are necessary to extend the new rock typing method to multiple wells penetrating multiple capillary windows. In the aquifer window, the new method for rock classification is not practical because of the absence of capillary pressure. One important conclusion is that rock typing based on water saturation needs to be exercised with caution in different capillary windows to honor the reservoir's saturation-height behavior.
Flow of Polyacrylamide Polymers in the Near-Wellbore-Region, Rheological Behavior within Induced Fractures and Near-Wellbore Area
Authors: Zechner Markus , Buchgraber Markus , Clemens Torsten , Gumpenberger Thomas , Castanier Louis M. , Kovscek Anthony R.
Published: June 2014

The economics of polymer solution injection projects are dependent on the improvement of displacement efficiency over waterflooding, the injectivity of polymer solutions, and reduced lifting costs associated with oil production and reduced water cut. High molecular weight polyacrylamide polymers show shear-thinning behavior when measured in a rheometer while they show shear-thickening behavior in cores.

Micromodel experiments were used to investigate the rheological properties of polyacrylamide polymers at the high flow velocity conditions occurring in the near-wellbore region of wells. The results show shear-thickening characteristics. In addition, some plugging of the models by polymers was observed despite filtering of solutions. Also, core flood tests were performed. For the core-flood tests, severe degradation of the polymers was observed for high flow velocities.

The data gathered from the experiments was used to interpret the results of a polymer solution injection test performed in the 8 Torton horizon reservoir in Austria. Shear-thickening behavior of the polymers would lead to very high well-head pressures. Through introduction of the degraded polymer viscosity data obtained from the laboratory experiments, the injection pressure observed in the field is explained.

The field test showed that after a first phase of polymer solution injection under matrix conditions, a second phase with injection above the formation parting pressure (FPP) exists. To investigate the polymer rheology during this phase, micromodel experiments with various fracture geometries were conducted. The results show that within the induced fractures, polymer solutions show shear-thinning behavior and no substantial degradation of the polymers is seen. Owing to the low flow velocities through the fracture planes into the formation, also within the formation, no severe degradation of the polymers is expected.

Hence, high molecular weight polyacrylamide polymers should be injected above the FPP when high flow velocities are expected in the near-wellbore region and such injection is permissible.
Horizontal Well Fracture Initiation and Extension from Cemented Cased Wells
Authors: Daneshy Ali
Published: June 2014

This paper discusses two critical aspects of fracturing in cemented cased horizontal wells; the role of cement bond strength in fracture initiation, and the influence of spacing between perforation clusters on fracture width. It shows that opening of inclined and transverse fractures requires shear sliding between the formation and cemented casing. Strong cement bond or external casing attachments near the perforated interval hinder this shear sliding and hamper free opening of the fracture. If the initiated fracture is longitudinal, its opening causes tensile failure of the bond between casing and cement. This enhances the link between fracture and perforations and assists successful execution of the job. Close spacing between perforation clusters also results in fractures that are narrower than predicted by theories of fracture mechanics. Furthermore fracture width tapers quickly as it extend beyond the wellbore. Together these two mechanisms can explain why these types of fractures are known to occasionally encounter operational problems that include inability to inject at the planned rate during the early stage of each fracture and sudden screen-outs even with very low proppant concentration.

The paper offers perforation recommendations for enhancing borehole/fracture connection, as well as guidelines for successful execution of the treatment.
Modeling Viscosity Response of Fracturing Fluids from Flowback and Produced Water using Advanced Cooperative Optimization Algorithms
Authors: Fontenelle L. K. , Chen D. , Schnoor E. , Haggstrom J. , Perkins D.
Published: June 2014

As water management becomes a more prominent aspect of completion and production strategies within the oil and gas industry, some operators use flowback and produced water in place of fresh water during fracturing operations. These strategies help reduce the volume of fresh water used, thus lowering the environmental impact during completion and production operations. Because the highly optimized legacy formulations that provide optimal proppant transport have been formulated with relatively pure water sources, using flowback and produced water (which can contain dissolved minerals from the formation or byproducts of spent fracturing fluid) can prove challenging when trying to obtain predictable fracturing fluid properties. Reusing flowback or produced water typically involves reformulating the fracturing fluid through optimization for the specific source water, which can be a time-intensive process with high uncertainty associated with limited design experiments.

This paper presents a method for determining the chemical formulation to achieve a specific viscosity and time profile for a fracturing fluid based on the chemical constituents of the source water. The process uses neural network as a basis for modeling fracturing fluid viscosity over time after mixing. Once the viscosity is calculated from the empirical formulation, the chemical components are re-estimated through inverse neural network models to validate the previous selection. The optimization of the fluid formulation is implemented with a multiobjective genetic algorithm to determine the best selection of chemical components necessary for producing a specific viscosity profile. The results from the fluid simulations and actual testing are also discussed to demonstrate the different applications.
High Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of GoM Oil Mixed with Nitrogen
Authors: Hustad Odd Steve , Jia Na Jenna , Pedersen Karen Schou , Memon Afzal , Leekumjorn Sukit
Published: June 2014

This paper presents high pressure PVT measurements and equation-of-state (EoS) modeling results for a GoM oil and for the oil mixed with nitrogen in various concentrations. The data includes:

Upper and lower asphaltene onset pressures and bubble point pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94°C (201.2°F) asphaltene precipitation is seen after addition of 27 mole % of nitrogen. Viscosity data for the swelled fluids showing that addition of nitrogen significantly reduces the oil viscosity. Slim tube runs indicating that the minimum miscibility pressure of the oil with nitrogen is significantly higher than estimated from published correlations.

The data has been modeled using the volume corrected Soave-Redlich-Kwong (SRK) and the Perturbed-Chain Statistical Association Fluid Theory (PC-SAFT) EoS. While both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid phase compressibility of the reservoir fluid swelled with nitrogen.

Nitrogen gas flooding is expected to have a positive impact on oil recovery due to its favorable oil viscosity reduction and phase behavior effects.
Microresistivity Image Inpainting and Visualization
Authors: Assous S. , Whetton J.A. , Elkington P.A.
Published: June 2014

Borehole microresistivity images are an important source of high resolution information with broad application in geology and petrophysics. They contain large volumes of data which (for reasons of efficiency and reproducibility) makes it desirable to automate aspects of quantitative analysis such as feature extraction. One of several hurdles to be addressed in this challenge is the typically incomplete circumferential coverage of measurements from wireline tools (often less than 70%). Robust estimates of the missing information have been obtained by decomposing the measured parts into sparse representations of their morphological components using dictionaries of multi-scale, multi-orientation transforms; reconstructing these representations recovers missing information to an extent dependent on the dictionaries. In clastic rock formations the most useful transforms are found to be curvelets, which have been used to reconstruct a broad range of attributes including common continuous curvilinear features such as partial and full sinusoids, as well as textural elements. The method has been tested on full-coverage data from small diameter wells artificially obscured to simulate partial coverage. For images dominated by curvilinear features, reconstruction accuracy is 92% for 50% coverage loss (typical in 12.25 inch diameter wells), and at 30% loss (typical in 8.5 inch wells) images are almost indistinguishable from the original unobscured images for all apparent dip angles below near-vertical, regardless of degree of feature parallelism (or lack thereof). Successful reconstruction of near-vertical features (including those with complex boundaries such as breakouts) is more dependent on coverage loss, but in these cases the results are consistent with judgments made by human interpreters. The utility of these inpainted images is further enhanced by visualizations that improve on the universally-used static and dynamically normalized image displays by (for example) rendering wide dynamic range data without introducing unwanted artefacts. The image inpainting and visualization methods described are enablers for automated feature recognition.
65 Years of Fracturing Experience: The Key to Better Productivity is Not What we Have Learned but What we Have Forgotten and Failed to Utilize!
Authors: Syfan Frank E. , Palisch Terry T. , Dawson Jeffrey C.
Published: June 2014

Many engineers today do not have the training needed to fully understand the importance of fracture mechanics principles and are easily overwhelmed in trying to deal with proper proppant and fluid selections, perforation design and strategy, and on-site quality control of the fracturing process. The unfortunate reality is that many fracture designs are improperly engineered with critical reservoir and hydraulic fracture parameters either ignored or improperly addressed. Many completions are either marginally economical or produce at reduced commercial rates. Regardless of reservoir type, it is critically important to achieve a highly conductive hydraulic fracture that provides connectivity between the reservoir and the wellbore.

Since its inception, fracturing and completion knowledge has expanded exponentially allowing the oil and gas industry to develop ultra-low permeability unconventional reservoirs. During the 1980's and 1990's technology pioneers such as Holditch, Nolte, Warpinski, Veatch, and others, further developed the principles of fracturing which recognize the importance of critical fracture parameters and their effect upon initial productivity and ultimate recovery. These gains in expertise have resulted in unprecedented activity in the Bakken, Eagle Ford, Barnett, Haynesville, and Marcellus with increasing activity in new reservoirs such as the Utica, Niobrara, and Mississippian. Although each of these reservoirs is unconventional, each is uniquely different with respect to lithology, permeability, and hydrocarbon chemistry and interaction.

This paper will challenge the industry notion that infinitely conductive fractures are being placed in many unconventional completions. It further addresses the critical fracturing parameters required to achieve a high conductivity fracture, why they are important, and how to achieve proper proppant and fluid treatment designs. The importance of these fundamental principles is documented and illustrated by several case histories which demonstrate the value of achieving high conductivity fractures and the effects of improper design. This paper should be of great value to completion and operations engineers to help further their knowledge with regard to the importance of fracture conductivity and connectivity in all hydraulic fracturing applications.
New Blood to the E&P: How to Attract, Educate and Train New E&P Professionals
Authors: Suarez A. , Ford J. T.
Published: June 2014

The E&P industry is recognized to have cyclical behavior in respect to the need for new professionals, strongly linked to the level of activity related to the variations in oil and gas prices. The strong ups and downs on E&P activities create problems to properly solve the crew exchange equation with Companies' needs for new employees to be aligned with the retirement of experience professionals.

This paper presents the approach that Repsol has implemented, as a Global-Latin multinational IOC, in order to solve a much debated E&P industry problem on how to attract and hire first, and after that, how to educate and train for the E&P new professionals worldwide.

The much debated IOC's recurrent problem relates in this particular case to the needs of an IOC based within a nonbearing hydrocarbon country. It is them more important for the analysis to start with an inside reflection about the key differential characteristics of the Exploration and Production as an industry, then to follow with the identification of what are the common ingredients present on reputed good professional/managers from successful IOC's, thus to define what it is needed to be a successful professional on the E&P.

In order to be attractive and to attract the right profiles of students graduating at Universities worldwide, the IOC has to be aware on the big differences from how we do see ourselves and our industry, and in perspective, how are we perceived by society, as a way to understand, recognized and remediate the present lack of attraction or interest of our industry for the best talent coming out from Universities.

The above referred concerns are critical for Repsol as translated into the specific environment for a Latin-Global multinational that followed a strong period of growth expansion by acquisitions throughout the 90's, taking the Company into the top ten E&P IOC's. To overcome that problem, a tailor made approach was the selected solution, and an in-house intensive "Master E&P" course was designed in 1998-99, as a tool to attract and educate any new young professional recently graduated to be hired for its Upstream.
Successful HP/HT Drilling Through Innovative Practices: Sharing a Case Study of a Deep HP/HT Well
Authors: Syazwan M. , Yap Y. , Umar L. , Pepple M. M.
Published: June 2014

Despite the short planning time of 18 months and very limited geological data, TTD-1 HPHT Exploration well in Block SK of East Malaysia, was successfully drilled to its technical limit by adopting some innovative HPHT practices. Various technical challenges were successfully overcame including an abnormally steep pressure ramp (17 psi/ft), high mud weight (18 ppg), high overbalance (3,000 psi), narrow drilling margin (until 0.7 ppg window), wellbore breathing, pore pressure of 14,000 psi and temperatures of 325° F.

During drilling, the actual operating window was successfully mapped out in real-time. The lower boundary was defined by pore pressure modeling, MDT logging and dynamic flow checks using MPD. The upper boundary, fracture gradient, was derived from dynamic formation integrity tests & leak-off tests utilizing MPD. Other techniques such as use of smaller tubular, low-flow MWD tools and bridging agent also contributed to the success. Wellbore breathing was well controlled to a minimum level.

Various simulations have assisted the HPHT section to be drilled beyond conventional defined limits. Two real-time monitoring centers assisted in improving drilling efficiency and real-time decision making. The well highlighted limitations of acquiring formation pressure in tight formation using FPWD tools, life of MPD seal element and gas invasion in production zone cementation.

The authors will present and share the HPHT drilling practices adopted to successfully drill the deepest HPHT well to date for PETRONAS Carigali in Malaysia.
Data Driven Analytics in Powder River Basin, WY
Authors: Maysami Mohammad , Gaskari Razi , Mohaghegh Shahab D.
Published: June 2014

In the past few years, we have observed the introduction of smart technologies that adapt themselves to the specific needs of individual users. There are many mobile and web-based services with learning capabilities that play the role of a personal assistant in our daily life. The foundation of this new class of services is a paradigm shift from intensive computational modeling and simulation of complicated phenomena toward data driven analytics. The oil and gas industry with the uncertainties convoluted into our measurements and understanding of the subsurface should not be excluded from this recent paradigm shift. Data driven analytics have proven to be a powerful alternative to conventional numerical and analytical solutions. In their advanced form, data driven technologies may be used as comprehensive management tools of oil and gas assets.

In this paper, we study Hilight field in Powder River Basin, a mature field with large number of wells. Lack of sufficient dynamic data such as flowing pressure for mature fields is common among these types of fields. Conventional data analyses impose a challenge in the absence of time-variant field measurements in addition to production history. Acquisition of a comprehensive data set for oil and gas assets, in general, is a costly luxury that is not financially feasible for all investment budget ranges. Data-driven approach along with pattern recognition techniques can introduce a potential solution to this challenging task and extract practical and valuable insights which can be vital to identification, planning and developments of assets and plays.

In this work, data from nearly 400 wells has been analyzed. Data from completion and workover was partially available. Well logs for only 15 wells is accessible providing less than 10% petrophysical data attributes over the entire well sets. Available production rate history for 185 wells starts from June 1969 and extends until April 2012. The information value of this dataset is investigated through a multi-step workflow. The workflow includes reservoir delineation and geological modeling, volumetric reserve and recovery factor estimations, production decline curve analysis, fuzzy pattern recognition (FPR) analysis and key performance indicators (KPI) analysis. FPR analysis provides time-laps spatial patterns, enabling us to qualitatively study the reservoir depletion and fluid flow in Hilight field. The result of these analyses has been used to identify the depletion distribution over time and sweet spots for infill locations. KPI analysis identifies relative influence of different parameters on hydrocarbon production. Top-Down Model is developed and used for field development planning and economic analysis on proposed new wells. The workflow has a minimal computational footprint compared to conventional methods. It has been demonstrated how these data driven techniques can be employed as a guide toward an improved reservoir management and planning.