bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wellbore Stability Considerations for Drilling High-Angle Wells Through Finely Laminated Shale: A Case Study From Terra Nova
Authors: Gallant Chris , Zhang Jianguo , Wolfe Christopher A. , Freeman John , Al-Bazali Talal , Reese Mike 
Published: December 2007

AbstractHigh angle wells drilled into finely laminated shale are often found to be less stable than comparable wells drilled into non-laminated rock. This can be attributed to a variety of factors including, but not limited to, well trajectory, the in-situ stress field, rock strength anisotropy, shale reactivity issues, chemical imbalances between the drilling fluid and shale pore fluid, and many others. However, due to the lack of available data some of these mechanisms are difficult to quantify and therefore are typically not accounted for during well planning. This can result in significant wellbore instability issues that substantially elevate drilling operation costs.In this paper, a comprehensive approach to account for many of these wellbore instability mechanisms is outlined. A plane-of-weakness model is utilized to account for the effects of weak bedding planes and other discontinuities. The model uses parameters that are obtained by curve fitting triaxial strength test results conducted at various angles with respect to bedding. Additionally, traditional mechanical and chemical effects were also addressed and incorporated into the pre-drill model to assist in well planning. The model was then implemented at the Terra Nova field for the case of a highly deviated wellbore drilled through finely laminated shale nearly parallel to bedding.Real-time monitoring of measurement and logging while drilling data was key to identifying the unstable sections so that the root cause of instability could be diagnosed. The appropriate remedial action was then applied and wellbore instability problems were mitigated.Both mechanical and chemical borehole instability models were applied in a case history to evaluate the potential for wellbore instability. In particular, bedding-plane related and chemically-induced instability were addressed and overcome through comprehensive modeling and the deployment of modified operational procedures.
Evaluation of Low-Resistivity-Pay Deepwater Turbidites Using Constrained Thin-Bed Petrophysical Analysis
Authors: Bastia R. , Tyagi A. , Saxena K. , Klimentos T. , Altman R. , Alderman S. , Bahuguna S. 
Published: December 2007

Abstract
A novel methodology has been developed to evaluate low resistivity pay reservoirs in very thin, laminated sand-shale sequences. This technique combines information from both high and low resolution logs to model the petrophysical properties of thin bedded formations. The result is a set of modeled high resolution logs that can be used to yield more accurate estimations of porosity, water saturation and permeability.
A high resolution and a low resolution log response are selected and binned into discrete lithofacies. The average low resolution log responses are statistically calculated for each lithofacies. An initial model is generated by using the high resolution lithology index to select the corresponding low resolution response for each lithofacies, resulting in a set of high resolution logs for each input log. By applying a corresponding vertical response filter to the high resolution log, a synthetic log is created which can be compared to the original. A minimization technique is used to adjust the high resolution responses such that the synthetic and actual logs agree. Since there are an unlimited number of high resolution logs which could result in the same synthetic response, the process is constrained using limits defined for each lithofacies. Evaluation of hydrocarbons in place is then performed on the resulting model.
This paper documents examples in deep-water turbidite reservoirs where thin beds on the scale of a few centimeters were evaluated using this technique. The observations were consistent with core data where this was available. Thin bedded silt and shale laminae had a disproportionate effect on standard resolution measurements due to the abundance of montmorillonite clay which caused elevated neutron and suppressed resistivity responses. The constrained thin-bed analysis yielded considerable enhancement of hydrocarbons in place compared with the evaluation using only standard resolution measurements.
Thin bedded laminated reservoirs occur in many hydrocarbon provinces. The technique described in this paper provides an alternative method for evaluating these formations, helping to reduce reserves uncertainty during a time where accurate reserves evaluation continues to receive high attention.
Effect of Well Variables on the Performance of Chemical, Jet, and RCT Tubing Cutters
Authors: Jurgens M. S. 
Published: December 2007

Abstract
An analysis of 72 tubing cuts made during Shell deepwater workovers in the Gulf of Mexico was completed to determine the effect of well variables on the cutting performance of chemical, jet, and radial cutting torch cutters.
An initial pre-study analysis indicated that cutting success was only 65%, 50%, and 77% for the chemical, jet, and radial cutting torch cutters, respectively. It was found that some cutting failures could be attributed to specific causes, such as heavy paraffin in the well, improper detonation, low-pressure tool leaks, exceeding tool pressure limits, and improper tool gas ventilation; however, other failures did not have any apparent cause. These remaining cuts were analyzed against specific well variables to look for trends that may indicate the cause of failure.
It was determined that chemical cutter success in CaBr2 completions fluids was much lower than all other fluids combined. Specifically, cuts in bromide fluids accounted for 71% of the total number of failed cuts, but only comprised 32% of total attempted cuts. Further investigation indicated that bromide fluids may react more violently with the bromine trifluoride acid than the other types of completion fluids used. From this analysis, it is believed that less acid will be available to sever the pipe wall when cutting in bromide fluids.
Additionally, it was found that placing the pipe in tension significantly increased cutting performance. No other significant correlations were found to other well variables.
Multiscale Methods for Modeling Fluid Flow Through Naturally Fractured Carbonate Karst Reservoirs
Authors: Popov P. , Qin G. , Bi L. , Efendiev Y. , Ewing R. , Kang Z. , Li J. 
Published: December 2007

Abstract
Modeling and numerical simulations of Carbonate Karst reservoirs is a challenging problem due to the presence of vugs and caves which are connected via fracture networks at multiple scales. In this paper we propose a unified approach to this problem by using the Stokes-Brinkman equations which combine both Stokes and Darcy flows. These equations are capable of representing porous media (porous rock) as well as free flow regions (fractures, vugs, caves) in a single system of equations. The Stokes-Brinkman equations also generalize the traditional Darcy-Stokes coupling without sacrificing the modeling rigor. Thus, it allows us to use a single set of equations to represent multiphysics phenomena on multiple scales. The local Stokes-Brinkman equations are used to perform accurate scale-up. We present numerical results for permeable rock matrix populated with elliptical vugs. Both constant and variable background permeability matrices are considered and the effect the vugs have on the overall permeability is evaluated. Fracture networks connecting isolated vugs are also studied. It is shown that the Stokes-Brinkman equations provide a natural way of modeling realistic reservoir conditions, such as partially filled fractures.
Evaluation of Infill Drilling Opportunities in Lekhwair Field, Oman
Authors: Jayanti Shekhar , Chopra Anil , Giordano Ronald M. , Yuan Hua , Tie Hongguang , Suleimani Ali , Gheithy Ali , Edwards Clement 
Published: December 2007

Abstract
This paper presents an evaluation of infill drilling opportunities in a mature waterflood. Different infill drilling configurations for increased oil recovery are compared using a ranking scheme. The field has been on production since 1976. The field has a complex development history, with periods of primary recovery, shut-in, 5-spot, inverted 9-spot, and direct line-drive waterflood. The field is currently undergoing a linedrive waterflood. The challenge is to find new infill drilling opportunities and determine optimal well spacing to maximize oil production.
Traditional infill drilling evaluations either use empirical techniques based on ad-hoc esimates of drainage areas or reservoir simulation of the field-level benefits of an infill drilling program. The former approach ignores the impact of reservoir heterogeneities while the latter approach makes it difficult to evaluate the contribution that each infill well makes to the field-level benefit. Our approach isolates the impact of each infill well and provides a fast and novel methodology to evaluate the incremental benefit while accounting for reservoir heterogeneity, well conditions, pattern configuration, injection rates, and voidage replacement ratio. This type of analysis helps optimize the number of wells to be drilled and at the same time leads to increased oil recovery through better waterflood management.
Streamline analysis was used to identify dead spots and regions of unswept oil in a part of the field. A novel waterflood management workflow was used to evaluate new infill well configuration strategies to increase oil recovery and better manage the waterflood. Optimization studies were also conducted to minimize the number of wells with the right combination of injectors and producers and obtain significant incremental benefits. Work is underway in the field to implement these recommendations and early results point to the success of this approach.
This paper presents a novel approach for evaluating the impact of infill drilling. The marginal utility of each infill well is calculated and then is used to optimize the number of wells and maximize oil recovery. The approach presented can be used to quantify the impact of infill drilling and increase oil rate and recovery in similar reservoirs.
Porosity Determination From NMR Log Data: The Effects of Acquisition Parameters, Noise, and Inversion
Authors: Bachman H. N. , Crary S. , Heidler R. , LaVigne J. , Akkurt R. 
Published: December 2007

Abstract
An ongoing challenge for nuclear magnetic resonance (NMR) well logging is that the quality and utility of the data depend on the acquisition sequence, inversion parameters, and the logging environment. Some modern NMR logging sequences are intended to be applicable over a wide range of environments, and include measurements of transverse relaxation (T2), polarization (T1), and diffusion (D). But compromises are inevitable for any given NMR technique. For example the overall acquisition time is dictated by operating at "reasonable" logging speeds, so full polarization of long T1 fluids is rarely achieved. Additionally, the inversion process creates interdependencies between T1, T2 and D. These effects conspire to introduce inaccuracies in the reported porosity.
We investigate the influence of acquisition parameters, inversion parameters, and noise on the determination of porosity from NMR data. A key focus is on fluids exhibiting the extremes of T1, T2 or D such as light hydrocarbons, gas, water at high temperature, or heavy oil. We make this investigation by three methods. The first method is to calculate a porosity sensitivity curve as a function of T1, T2 and D for multiple acquisition modes. The second method is to invert simulated NMR echo data. Lastly, we compare real NMR log data porosities with other porosity logs in fields exhibiting long T1 constants. In all three cases, we show how porosity is under-or over-estimated beyond the expected accuracy based on random noise alone. The results are discussed in terms of what measures can be taken to identify and minimize these errors.
Life of Well Isolation Implemented in Major North Sea Development
Authors: Hunter Liz , Kinnaird Bill , MacLean Kerry 
Published: December 2007

Abstract
The Buzzard field operated by Nexen is the largest oil discovery in the North Sea since the early 1990s. About 27 production wells, of approximately 9,000 ft total vertical depth (TVD), will be drilled during the field life. Maximized life of well isolation is imperative. The production liners are being cemented with a life-of-well engineered solution.
The reservoir section consists of two discrete oil-bearing sandstones. Oil recovery will be maximized by water injection from subsea wells. Isolation of the production sands enhance management of the waterflood and thus maximize the producible volume. The challenge was to develop a cement system that could achieve and maintain isolation throughout the life of the field.
A finite element-based analysis tool was used to build a model of the reservoir section. The model was then used to predict the forces on the cement sheath throughout its life under all load conditions, including those caused by pressure and thermal changes during drilling, completion, and sustained production.
The model predicted that a conventional cement sheath could fail in three modes: debonding at the formation, compressive shear, and radial cracking. A cement sheath with lower Young's modulus, higher tensile strength, and shrinkage compensation was required. A series of designs were tested to select the optimum solution that met the life-of-well needs.
The successful implementation of this new approach to cementing required special planning and organization. To date, 13 wells have been cemented with the life-of-well solution, with no operational problems and indication of good placement.
Bond-log results differ from those expected from conventional slurries because of elastic components in the life-of-well slurry. Special data processing techniques have been developed to allow evaluation using conventional bond logs; these are presented in this paper.
Analysis, design, and field implementation discussed in this paper can be applied to field development in other locations where zonal isolation during the well life is critical.
Experimental Study of Oil/Water Flow With Paraffin Precipitation in Subsea Pipelines
Authors: Bordalo Sergio N. , Oliveira Rafael C. 
Published: December 2007

Abstract
The deposition of paraffins was studied in a laboratory simulation of the subsea operational conditions, where the oil pipelines laying on the seabed are subjected to low temperatures. An experimental apparatus was built for a pipe-flow model submerged in a chilling bath of near frozen water. Streamwise pressure and temperature gradients were measured to evaluate the differences in the behavior of paraffin deposition between one-phase oil flow and two-phase oil-water flow. Most works on the behavior of paraffin deposition consider one liquid phase only, while two phases – oil and water – are considered here. Measurements in two-phase oil-water flows show a reduction of the head loss compared to one-phase oil flows, when both are subjected to paraffin precipitation, and photographs show that the layer of paraffin deposits on the pipe wall was significantly reduced in the presence of water.
Impact of Flow Assurance in the Development of a Deepwater Prospect
Authors: Gonzalez Doris L. , Jamaluddin Abul K. M. , Solbakken Trond , Hirasaki George J. , Chapman Walter G. 
Published: December 2007

Abstract
In deepwater production systems, extreme pressure and temperature conditions, multipart sub-sea networks, complex reservoir characteristics, and various fluid phases flowing from the reservoir rock to the surface could promote production interruption due to the formation and deposition of hydrocarbon solids such as asphaltene, wax and hydrates anywhere in the production system. These are flow assurance key risk factors that create significant impact on field development planning, especially, when dealing with marginal deposits having varying fluid characteristics. To reduce the risk, we have adopted a systematic approach to evaluate the potential impact of asphaltene and wax precipitation and deposition.
In this field case, two distinct layers of hydrocarbon deposits are considered marginal from reserves point of view; the upper deposit is a gas condensate layer and the lower is a black oil layer. Because of marginal reserves, mono-bore commingle production was thought to be an option. Also, in-situ gas lifting is considered to be a favorable option. Commingling of live crude oil with a gas stream may lead to precipitation of asphaltenes resulting from changes in composition. Changes in pressure and temperature can also take the system across the boundaries of asphaltene and wax. Being able to predict the formation of solid deposits along the whole production system from downhole to production facilities becomes progressively more important as water depths increase.
This paper describes the impact of flow assurance considerations in a deepwater Gulf of Mexico development project. This study is based on experimental measurements of asphaltene and wax precipitation of a hydrocarbon fluid when contacted with gas condensate from another zone. The evaluation is performed using multiphase thermal-hydraulic behavior in an Integrated Production Model (IPM) that provides system deliverability predictions through the lifetime of the project coupled with asphaltene and wax thermodynamic models. The Perturbed Chain - Statistical Associating Fluid Theory (PC-SAFT) equation-of-state (EOS) model1,2 is the thermodynamic tool used to predict asphaltene precipitation. Wax deposition is predicted using a solid solution model.
The results of experimental and theoretical flow assurance assessment indicated that the black oil has the propensity for asphaltene precipitation caused by pressure depletion during primary production. Simulation results revealed that the downhole commingling with gas condensate is expected to significantly intensify the asphaltene precipitation condition. Results also indicate that wax precipitation will not be an issue during the life of the project.
A Novel Hydraulic Fracturing Model Fully Coupled With Geomechanics and Reservoir Simulator
Authors: Ji Lujun , Settari A. (Tony) , Sullivan R. B. 
Published: December 2007

Abstract
Unconventional fracturing techniques, such as high rate waterfracs, waterflooding or steam stimulation, produced water and cuttings re-injection, CO2 sequestration, N2, CBM stimulation etc., are difficult to model because of strong interactions among the fracturing process, geomechanical changes in the porous media, and reservoir fluid flow. The resulting strong poroelastic/thermoelastic effects, permeability/porosity changes, and possible rock failure (shear fracturing) make current conventional fracturing models inadequate in such circumstances. Therefore, it is necessary to develop new models which include all of these mechanisms and which are capable of integrated data analysis.
This paper presents a new fracturing model with all of these mechanisms included. The model fully couples fracture mechanics with reservoir and geomechanics simulation. This methodology allows us to model fracture initialization and propagation, post-frac multiphase cleanup in the reservoir and fracture, and pre- and post-frac well performance in a changing stress and pressure environment, all within the same system.
The model couples a three-dimensional (3-D) finite element geomechanics model with a conventional 3-D finite difference reservoir flow simulator. The geomechanics module implicitly models fracture propagation via displacements on the fracture face. The flow and geomechanics/fracturing are coupled in an iterative manner that is equivalent to full coupling of geomechanical modeling. The 3-D (planar) fracture geometry and pressure are the common dynamic boundary conditions for the flow and stress modules. The new iterative process yields smooth fracture propagation, and the model has been tested on classical fracturing problems.
A field example where we model a waterfrac stimulation performed in Bossier tight gas sands is presented to demonstrate the models' capabilities as well as the validity and advantages of the approach. The results show that the model is capable of matching a complex history of injections and calibrating the stress-dependency of formation permeability.
Analysis of Production Data From Hydraulically Fractured Horizontal Wells in Tight, Heterogeneous Formations
Authors: Medeiros F. , Kurtoglu B. , Ozkan E. , Kazemi H. 
Published: December 2007

Abstract
This paper discusses the analysis of production data from hydraulically fractured horizontal wells in tight, heterogeneous formations. We consider horizontal wells with longitudinal and transverse hydaraulic fractures, which might be surrounded by a region with natural fractures. These well-reservoir configurations are of interest in many unconventional reservoirs, including tight-gas sands and shale-oil or gas formations. A semi-analytical model that can incorporate the key features of reservoir heterogeneity and the details of hydraulic fracture and wellbore flow is used to compute production decline. Production decline characteristics are presented in terms of transient productivity index. Computation of transient productivity index from field data and the analysis of production decline by transient productivity index are explained. Example applications of production data analysis for fractured horizontal wells in tight, heterogeneous formations are presented.
Gas Production From Class 2 Hydrate Accumulations in the Permafrost
Authors: Moridis George J. , Reagan Matthew T. 
Published: December 2007

Abstract
Gas hydrates are solid crystalline compounds in which gas molecules are lodged within the lattices of ice crystals. Natural hydrates in geological systems are composed mainly of methane. The amounts of hydrocarbon gases trapped in natural hydrate accumulations are enormous, leading to a recent interest in the evaluation of their potential as an energy source. Class 2 hydrate deposits are characterized by a Hydrate-Bearing Layer (HBL) underlain by a saturated zone of mobile water, and are encountered in the permafrost and in deep ocean sediments. The base of the HBL in Class 2 deposits may occur at the edge of, or within, the zone of thermodynamic hydrate stability. Because of the manner of their formation from pre-existing gas reservoirs, permafrost hydrate deposits are generally characterized by high hydrate saturations and are bounded by relatively impermeable strata.
In this numerical study of long-term gas production from permafrost Class 2 deposits, we investigate three different well configurations that involve different production intervals and combinations of depressurization (the main dissociation-inducing mechanism) with localized thermal stimulation. Using high-definition grids and realistic production scenarios, we determine that large volumes of gas can be produced at high rates (several MMSCFD) for long times using conventional technology. The production approach involves initial fluid withdrawal from the water zone underneath the HBL. The production process follows a cyclical pattern, with each cycle composed of two stages: a long stage (months to years) of increasing gas production, and a short stage (days to weeks) that involves destruction of the secondary hydrate (mainly though warm water injection) that evolves during the first stage. A well configuration that initially involves heating of the outer surface of the wellbore and later continuous injection of warm water at low rates appears to yield the highest average rates over the period it takes for the exhaustion the hydrate deposit. We determine that gas production is affected by (a) the intrinsic permeability, (b) the initial hydrate saturation, (c) the fluid withdrawal rate, (d) the thickness of the water zone, and (e) the initial pressure and temperature of the hydrates.