bluuebunny/crossref_metadata_2025_split huggingface dataset:
Distillation Effects in Heavy Oil Recovery Under Steam Injection With Hydrocarbon Additives
Authors: Jaiswal Namit J. , Mamora Daulat D. 
Published: December 2007

Abstract
Recent developments such as Liquid Addition to Steam for Enhancing Recovery (LASER) of bitumen during cyclic steam injection (SPE 79011) indicate increased production with the use of hydrocarbon (C5+) as a steam additive. This was attributed to viscosity reduction of bitumen when in contact with the hydrocarbon additive. However, our study indicates that steam distillation - in addition to viscosity reduction - plays an important role in enhancing heavy oil recovery.
We have conducted an experimental and analytical study to investigate the effect of (i) distillation and (ii) propane as a steam additive, with the aim of enhancing recovery of 12°API oil from San Ardo field, California. Three distillation processes were investigated: dry-, steam-, and steam-propane-distillation, the latter at propane:steam mass ratio of 0.05. Distillation temperatures ranged from 115°C to 300°C and were increased in steps of 10°C. Distillation pressures ranged from 0 psig for dry distillation to 998 psig for steam- and steam-propane distillation (15°C superheated steam conditions). In addition, yields were measured for field conditions of 260 psig and a temperature range of 220~300°C. Samples at each cut were collected and analyzed to determine volume of water and weight and composition of the hydrocarbon.
Main conclusions from the study are as follows. First, final yield at 10°C superheated conditions is practically the same for steam- and steam-propane distillation, about 10 wt%, significantly higher than that for dry distillation, 5 wt%. This clearly indicates the importance of steam distillation on oil recovery during steam- or steam-propane injection.
Second, final yield at field conditions is practically the same for steam- and steam-propane distillation, about 18 wt%. Propane appears to have little effect on the distillation of heavy oil, possibly due to the following reasons: (i) lesser light fractions in the heavy oil, and (ii) less solvent effect of propane on non-paraffinic fractions as these are less abundant in heavy oil than in intermediate crude. Third, a multi-stage thermodynamic model was developed, calibrated and satisfactorily matched experimental results of yields. This analytical model may be used for rapid selection of steam additives to evaluate their distillation performance.
A New Treatment for Wellbore Strengthening in Shale
Authors: Aston Mark S. , Alberty Mark W. , Duncum Simon , Bruton James R. , Friedheim James E. , Sanders Mark W. 
Published: December 2007

Abstract
The increase in complexity and associated costs with wells as a result of infield drilling, drilling below old fields and striving for deeper targets has generated industry interest and attention in wellbore strengthening. This heightened interest is demonstrated in the number of recent publications that have been prepared on the subject. These have primarily focused on and described methods that are effective in raising the fracture resistance of permeable formations such as sands. However, a much bigger impact can be made on the overall drilling operation if it is also possible to strengthen low permeability rocks such as shale along with the sands. The industry has seen this as a major challenge and to date the technology and expertise required to achieve this has not been consistent or reliable.
This paper will demonstrate that wellbore strengthening in shale is indeed feasible. A treatment pill was developed in the laboratory and successfully field tested at a US land-based location. The treatment consisted of a blend of particulates (known as stress cage solids) and proprietary cross-linked gelling polymers which set with time. Properties of the system such as compressive strength, adhesion to shale and the sensitivity to temperature and pressure were evaluated, and modeling work was done to engineer the size and concentration of bridging solids required.
Field testing was carried out in a 50-ft section of competent shale below the 9⅝-in. shoe in an operation where oil-based mud was being used. The initial fracture gradient was measured using leak-off tests to establish the native formation strength. The treatment was squeezed and allowed to set under pressure before drilling out, leaving a strengthened wellbore. Formation Integrity Tests (FIT) were conducted to confirm the presence of the strengthening effect. The robustness of the treatment was demonstrated by circulating drilling fluid for increasing periods of time and performing further FIT tests.
The well was left in a strengthened state at the end of the test period.
This trial demonstrates that by using appropriate technologies and methods it is indeed possible to reliably raise shale fracture resistance.
Estimation of Fracture Porosity of Naturally Fractured Reservoirs With No Matrix Porosity Using Fractal Discrete Fracture Networks
Authors: Kim Tae H. , Schlechter David S. 
Published: December 2007

Abstract
Matrix porosity is relatively easy to measure and estimate compared to fracture porosity. On the other hand, fracture porosity is highly heterogeneous and very difficult to measure and estimate. When matrix porosity of naturally fractured reservoirs (NFR) is negligible, it is very important to know fracture porosity to evaluate reservoir performance. Since fracture porosity is highly uncertain, fractal discrete fractal network (FDFN) generation codes were developed to estimate fracture porosity. To reflect scale dependent characteristics of fracture networks, fractal theories are adopted. FDFN modeling technique enables the systematic use of data obtained from image log and core analysis for estimating fracture porosity. As a result, each fracture has its own fracture aperture distribution, so that generated FDFN are similar to actual fracture systems. The results of this research will contribute to properly evaluating the fracture porosity of NFR where matrix porosity is negligible.
Porosity, Permeability, and MHR Calculations Using SEM and Thin-section Images for Characterizing Complex Mauddud-Burgan Carbonate Reservoir
Authors: Al-Bazzaz W. H. , Al-Mehanna Y. W. 
Published: December 2007

Abstract
This paper presents the process, and, results of the analyses of pore/grain morphology of rock fragments, from Mauddud-Burgan reservoir rock in Kuwait, for porosity, permeability and means hydraulic radius (MHR) calculations. The images are captured using SEM and thin-section analyses.
In this study, 2-dimensional images are used to characterize the morphology of the grains and pores, using a two step process. In the first step, the image is captured using a backscattered electron detector (BSE) digital electron microscopy imaging, and thin-section photography. All of the grain/ pore features captured in the image are reported in micrometer units. In the second step, the area of such features is scanned using image analysis software that has the ability to accurately measure several morphological parameters of pore and grain spaces.
A robust technique of visual estimate is used, which has the advantage of speeding the image analysis process. The visual analysis software tool counts different pores and grains and also measures their shapes and sizes that are crucial for porosity, permeability, and MHR calculations.
Several morphological features were been selected for measurement, including: object count, area, perimeter, and roundness. These analyses were conducted twice for each selected image – once for grain morphology and once for pore morphology. Porosity, permeability and MHR features are calculated based on area of the pore/ grain features measured from two-dimensional images.
Enhanced Heavy-Oil Recovery by Alkali-Surfactant Flooding
Authors: Bryan J. , Kantzas A. 
Published: December 2007

Abstract
This study presents the results of laboratory core studies investigating the recovery mechanisms of alkali-surfactant flooding in heavy oil reservoirs. Specifically, mixtures of water and alkali-surfactant systems have been injected into cores containing heavy oil (11 000 mPa·s and 15 000 mPa·s). Salinity is varied in order to generate oil-in-water vs. water-in-oil emulsion systems, and the effects of generating different emulsions are compared.
The application of this work is for the many heavy oil reservoirs in countries such as Canada and Venezuela containing viscous oil that still has some limited mobility under reservoir conditions. Alkali-surfactant (AS) flooding has considerable potential for non-thermal oil recovery after primary production.
Experiments were performed on cores with varying permeability, at different AS injection rates. All tests were performed on gas-free oil systems. The response from direct injection of AS systems is compared to AS injection after waterflooding. Pressure and oil recovery information is obtained from core floods, and these results are interpreted based on a semi-theoretical framework obtained from phase behavior and bulk liquid studies. It is demonstrated that both oil-in-water and water-in-oil emulsions can lead to the recovery of additional oil.
Alkali-surfactant flooding is already an established technique in conventional oil reservoirs, whereby enhanced oil recovery is a result of reduced trapping of oil due to the lowered oil/water interfacial tension. In addition, the injection of these chemicals may lead to the formation of emulsions, as has been documented by previous researchers. In our work, we demonstrate that in heavy oil systems, emulsion formation is a necessary requirement for the production of heavy oil. When these emulsions form, AS injection can lead to considerable improvements in the flooding response, even without the addition of polymers to stabilize the flood.
The Evolution of the Heavy-Oil-Exploratory-Well Testing Methodology—A Case History From Block 39 in the Amazon Rainforest of Peru
Authors: Prioletta Antonio , Cadena Jaime , Cachutt Rafael , Sersen Mateo , Flores Jose G. , Loli Manuel 
Published: December 2007

Abstract
The exploration for oil and gas is increasing in Peru, with 37 exploratory blocks currently under contract. Repsol YPF has an aggressive exploratory program for Block 39 in the Amazon rainforest of Northeastern Peru. Three wells have been drilled in the last two-year exploration campaign, all resulting in the discovery of heavy oils (API&lt;15°, μ0&gt;500 cp, GOR&lt;40 scf/stb) from the Casablanca, Chonta and Vivian formations, consisting of reservoirs with excellent rock properties, but lacking sufficient energy to flow to the surface.
To be able to accurately assess the value of the discoveries, it was necessary to evaluate each of the prospective horizons via Drill Stem Tests (DST). However, testing heavy oil reservoirs via DST is a challenging problem, as stable production rates, important for the analysis of pressure transients, are seldom encountered. Due to heavier densities, lower solution gas volumes and higher viscosities, heavy oil reservoirs stand a lower chance of flowing to the surface than lighter oils. The problem is further complicated in the case of exploratory wells, where little can be anticipated in terms of knowledge of the reservoir properties, reservoir fluids and pressures.
The conventional exploratory well testing procedure in the area consists of perforating runs with either wireline or Tubing Conveyed Perforating (TCP) and separate DST runs, with questionable results in terms of quality evaluation of the reservoirs. The heavy-oil exploratory wells of Northeastern Peru needed an assembly capable of perforating, testing and artificially lifting the fluids to the surface for adequate production, sampling and reservoir evaluation, and that also reduced the time and cost associated with the testing of exploratory wells.
Different configurations, consisting of TCP perforating and DST tools, followed by separate ESP runs in combination with a DST string (to be able to shut-the-well-in downhole) were run in the first two discovery wells in Block 39. Based on lessons learned, a TCP-DST-ESP string was run in the third well with the purpose of perforating under dynamic underbalance conditions, producing at stable rates, sampling, and making downhole shut-ins, all in the same run. Results were outstanding, from both the operational and the reservoir evaluation sides, saving considerable rig time and resources, also achieving maximum reservoir productivity by minimizing formation damage.
This paper goes over the planning stage, the evolution of the well-testing methodology, and the field operational details, highlighting the technical results and most relevant achievements. The multi-disciplinary approach, combining well operations with reservoir engineering, well testing and artificial lift disciplines, was considered instrumental in achieving this project's outstanding results.
Modeling the Economic Impact of Cognitive Biases on Oil and Gas Decisions
Authors: Welsh M. B. , Begg S. H. , Bratvold R. B. 
Published: December 2007

Abstract
Cognitive biases have long been known to impact decisions taken under conditions of uncertainty [1, 2]. Previous demonstrations of these biases, however, have focused on their impact on a single, typically technical, parameter judgment rather than examining their potential impact on economics when applied to all of the judgments involved in a complex Oil and Gas (O&G) decision such as reservoir characterization. Herein, we model the impact of three individual biases – overconfidence [2], bias resulting from the trust heuristic [3] and availability [4] - to measure their effect on economic outcome as represented by NPV.
All three biases are shown to have marked effects on the estimated value of a project, not just its uncertainty. Overconfidence at the levels people commonly demonstrate shown to result in a $259 million dollar mistake in calculating NPV in our modeled decision – making a project with a negative NPV seem to have a positive NPV. Availability bias, as modeled herein, similarly acts to increase the apparent NPV of a project – making a project actually likely to result in a $55 million dollar loss seem to have an NPV of up to $329 million.
The trust heuristic differs slightly in that its use, rather than actively causing bias, prevents the use of techniques that reduce overconfidence. The model shows that incorporating the views of five experts rather than accepting the values provided by the best of the five reduces overconfidence by 10%, even when agreement between the experts is high. Referring this back to our overconfidence model results, we note that this equates to a difference of up to $125 million in the mean NPV of the project.
On the basis of our findings, we argue that industry personnel be educated in the psychological limitations affecting decision making as awareness of their existence is the first step in reducing their effect [5]. Further, the inclusion of such material in petroleum engineering and geosciences curricula would be an effective way of ensuring that knowledge of cognitive biases spreads across the industry [6].
Barnett Shale Completions: A Method for Assessing New Completion Strategies
Authors: Leonard R. , Woodroof R. , Bullard K. , Middlebrook M. , Wilson R. 
Published: December 2007

Abstract
Activity in the Barnett shale of north Texas has continued to surge over the past several years, and with this surge in activity has come a steady evolution of completion strategies. Most operators agree that the best Barnett shale wells are those that have the most extensive fracture network development. One of the biggest challenges facing operators has been determining which completion strategy will create the largest fracture network along with identifying the most cost-effective diagnostic methods for evaluating those strategies and ultimately optimizing the completions.
This paper will describe an integrated completion diagnostic methodology for assessing and potentially optimizing Barnett shale completion strategies. The methodology described employs radioactive tracing and logging together with chemical tracing and conventional completion metrics to evaluate the effectiveness of Barnett completions.
This methodology will be utilized to assess the effectiveness of four pairs of simultaneously-fractured parallel horizontal laterals located in three different areas stretching from the western edge of the Barnett "Core Area" to the western edge of the play's expansion acreage. Key completion parameters were identified that can be used to optimize future Barnett completions in this and potentially other areas within the basin.
Sensitivity of Project Economics to Uncertainty in Type and Parameters of Oil Price Models
Authors: Begg S. H. , Smit N. 
Published: December 2007

Abstract
Dynamic price models (which replicate the characteristics of real price fluctuations over time, not just the mean) are a crucial element in economic evaluations. However, there has been little systematic evaluation of the effects of uncertainty in what type of model is most appropriate, or of uncertainty in the parameters of such models.
We present the results of a sensitivity analysis of economic metrics to uncertainty in both type of oil price model and in the values of the model parameters. Uncertainty in both arises from arbitrary choices in their derivation from historical data and from uncertainty as to whether the past predicts the future.
We take four types of price model (simple probabilistic, Geometric Brownian Motion, mean reverting, mean-reverting with jumps) and use historical data to derive estimates (and uncertainty therein) of the numerical values of their respective parameters. The impact of model choice and parameter uncertainty is then compared via their impact on economic metrics for a typical field development decision.
Application of Convolution and Average Pressure Approximation for Solving Nonlinear Flow Problems—Constant Wellbore Pressure Case
Authors: Zhakupov M. , Ilk D. , Blasingame T. A. 
Published: December 2007

Abstract
"Real gas" flow problems (i.e., problems where the gas properties are specifically taken as implicit functions of pressure, temperature, and composition) are particularly challenging because the diffusivity equation for the "real gas" flow case is strongly non-linear. Whereas different methods exist which allow us to approximate the solution of the real gas diffusivity equation, all of these approximate methods have limitations (including numerical models).
The purpose of this work is to provide a direct solution mechanism for the case of time-dependent real gas flow which uses an approach that combines the so-called average pressure approximation (a convolution for the right-hand-side nonlinearity) and the Laplace transformation. For reference, Mireles and Blasingame used a similar scheme to solve the real gas flow problem conditioned by the constant rate inner boundary condition.
In this work we provide a direct solution scheme to solve the constant pressure inner boundary condition problem. Our new semi-analytical solution was developed and implemented in the form of a direct (non-iterative) numerical procedure and successfully verified against numerical simulation.
Collecting Single-Phase Retrograde Gas Samples at Near-Dewpoint Reservoir Pressure in Carbonates Using a Pump-Out Formation Tester with an Oval Pad
Authors: Jones Chris , Alta Wandi , Singh Jorawar , Engelman Bob , Proett Mark , Pedigo Bob 
Published: December 2007

Abstract
Collecting representative, single-phase retrograde gas samples from heterogeneous fractured carbonate formations is challenging, especially for cases in which the reservoir pressure narrowly exceeds the dewpoint. Conventional wireline probe/packer assemblies are undesirable in this situation because their small diameter probes increase the pressure drawdown, compared to other available intake configurations. Furthermore, the likelihood of establishing hydraulic communication with an open fracture or vug is low with a ½-in. diameter probe, compared to setting straddle packers spanning a 1-m formation interval. The straddle packer intake geometry reduces the drawdown pressure required to establish flow, thus maintaining the flowing pressure above the dewpoint and preventing the onset of unwanted condensation.
Inflatable straddle packers can be run with pump-out test tools, but they have temperature, pressure, and operational limitations. The new Oval Pad* design, an elongated oval-shaped probe/pad assembly, possesses many of the advantages of dual packers without their limitations. Like a straddle packer, the Oval Pad tool is effective when testing thinly laminated and tight formations as well as fractured or vuggy carbonates. The oval shape enables the pad to encompass a significant vertical length of the borehole while establishing a pressure seal with the formation.
A retrograde gas reservoir is contained within the vuggy carbonates in the Jambi Merang area of South Sumatra. Here the reservoir pressure narrowly exceeds the dewpoint. Pressure must be maintained above the dewpoint during sampling operations to prevent unwanted phase separation. The RDT pump-out tester was fitted with Oval Pad and nitrogen-charged sample bottles to collect single-phase samples and to keep the phase intact until PVT properties can be analyzed in the laboratory. These samples were necessary to determine laboratory PVT properties and to define a production strategy.
This paper presents the details and challenges of the successful collection of single-phase samples in this environment.
Advanced LWD and Directional Drilling Technologies Overcome Drilling and Completion Challenges in Lateral Wells of Barnett Shale
Authors: Janwadkar Sandeep , Morris Stephen , Potts Mike , Kelley Jeff , Fortenberry David , Roberts Geoff , Kramer Mark , Privott Steve , Rogers Tom 
Published: December 2007

Abstract
The Barnett Shale field of North Texas is the most prolific and fastest growing natural gas field in North America.1 The field has a multi-trillion cubic feet equivalent of upside potential, but efficient extraction of natural gas from the Barnett shale poses drilling and completion challenges.1 Low porosity in the horizontal interval makes hydraulic fracturing essential.
Some of the major drilling challenges that affected drilling efficiency were unacceptably low penetration rates, premature bit damage, high torque, and drag. Engineers determined that drillstring buckling, bit whirl, and stick-slip were resulting in inefficient transfer of weight on bit, premature bit damage and reduced ROP. To overcome this challenge, BHA and drill string modeling were used to eliminate buckling and improve transfer of weight to the bit. Additionally, advanced directional drilling technologies were implemented that significantly improved drilling performance.
Planning the hydraulic fracturing program requires a precise evaluation of the bedding planes and fracture sets, both natural and induced. In the past, resistivity imaging tools were run on wireline to acquire this information. To obtain this information in horizontal wells, logging while drilling (LWD) tools were tried. The initial runs generated images of low resolution, and as a result, the rate of penetration had to be controlled to improve the image quality. To overcome this challenge, state-of-the art LWD tools were developed to acquire high-resolution resistivity images while drilling, and at twice the rate of penetration previously possible.
This strategy has been implemented to drill several wells in the Barnett Shale with excellent results. BHA and drill string modeling, coupled with advanced LWD and directional drilling tools, have significantly improved drilling performance. The rotating hours have reduced from 330 to 165 hours per well. A 48.39% reduction in days required (31.2 to 16.1 days per well) from spud to rig release has been realized.