bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fine-Scale Simulation of Sandstone Acidizing
Authors: Li C. , Xie T. , Pournik M. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
The current state of the art of sandstone acidizing modeling considers heterogeneities only in a very gross manner. The most sophisticated design models treat the formation as a series of layers with constant properties (mineralogy, permeability, etc.) in each layer. A radial variation in formation properties may be considered as a method of simulating the damaged region, but there is typically only two discrete regions considered – the damaged zone extending to some assumed radial distance, and the unaltered formation beyond this distance. However, sandstones invariably have small – scale heterogeneities in mineralogy and flow properties that may cause the effects of injected acids to differ greatly from what is predicted by a model based on a homogeneous formation.
Matrix acidizing of sandstone is influenced by very small-scale variations in the permeability field. Preferential flow of the acid through higher permeability pathways in the matrix allows much deeper acid penetration and better overall permeability response than is predicted by any current model of sandstone acidizing. This may be particularly important for high concentration HF treatments that are currently being applied, where channeling of the acid may create wormhole-like structures. In addition to variations in the permeability field, variations in the mineral distribution affect the stimulation achieved with acid. For example, a sandstone containing clay-rich streaks may experience a large permeability increase as the clay is dissolved by acid.
We have developed a fine-scale model of the sandstone core acid flooding process. The model divides the domain into grid blocks on the order of 0.1 inches on a side to simulate the fine-scale structure of sandstone. A highly variable matrix domain was generated by using standard geostatistical techniques, and the acid and mineral balance equations allowed us to predict the changing permeability field as acidizing proceeds. Permeability response to acidizing is predicted in which not only the porosity, but also the mineralogy, tortuosity, and statistical parameters of particle size are considered. The initial porosity and mineralogy field can be generated in a correlated manner in three dimensions; thus, a striated or laminated sandstone can be simulated by the model.
Application of the new model to typical acidizing conditions shows that acid tends to channel through a heterogeneous sandstone, with the most efficient acidizing occurring when the rock has a layered structure. Layering is simulated by assuming a correlated permeability field in the main flow direction, as occurs in sandstones having horizontal laminations. The model shows that acid can stimulate the matrix permeability two to three times farther into the rock than would be predicted with a standard acidizing model. The effects illustrated for acid penetration would also apply to other injection processes that rely on transport and chemical reaction in the matrix.
Analysis of Lost Circulation During Drilling in Cooled Formations
Authors: Hettema M. H. H. , Bostrøm B. , Lund T. 
Published: December 2007

AbstractA few of the lost circulation incidents that have occurred at the Statfjord field and the Veslefrikk field appeared to have been caused by drilling through cooled formations. These lost circulation incidents have been analyzed and compared with offset wells drilled with full returns. We have made plausible that the presented cases of lost circulation are caused by the fact that these wells have been drilled too close to a water injector. Injection data have been analyzed to determine the thermo-elastic stress changes around these injectors. To quantify the thermal cooling effect, downhole pressure data measured during the mud loss incident are analyzed. We found a significant reduction both in the breakdown pressure and minimum horizontal stress. When comparing these data with a thermo-elastic model, the theory predicts a much stronger effect than the interpreted downhole pressure measurements. Numerical simulations of near-wellbore thermal stress effects showed that differences between the mud temperature and the formation temperature could significantly increase the wellbore stresses toward compression. However, the combined near-wellbore thermal effects of formation cooling and a warm mud could not explain the discrepancy between the model and the interpreted stress measurements.
Characterizing Casing-Cement-Formation Interactions Under Stress Conditions: Impact on Long-Term Zonal Isolation
Authors: Mueller Dan T. , GoBoncan Virgilio , Dillenbeck Robert Lee , Heinold Thomas 
Published: December 2007

Abstract
The investigation of cement integrity over life of well conditions continues to be a high priority within the well cementing industry. Increasing awareness of problems associated with cement sheath failure and subsequent loss of zonal isolation or sustained casing pressure have demanded that set cement material behavior and the coupled behavior of casing, cement and formation be more fully understood in order to make rational engineering decisions. Recent advances in wellbore stress modeling can now provide a probabilistic determination of the suitability of a particular cement design for the expected range of induced well stresses.
This paper describes the cement evaluation and wellbore-modeling methodologies specifically developed to predict the magnitude of tensile or compressive forces created by changing wellbore or reservoir conditions.
Development & Field-Testing of a Cost Effective Rotary Steerable System
Authors: Moody M. , Jones S. , Leonard P. 
Published: December 2007

Abstract
This paper describes a new Rotary Steerable System (RSS) and results from its field testing program. The RSS has been designed to handle the technical requirements of the most challenging wells, but also to be economical for use in low cost wells. This important feature was achieved by a unique hydraulics and electronic design and through the use of durable but low cost materials. The tool itself consists of three active and independent steering blades placed close to the bit, and a near-bit stabilizer which acts as a fulcrum. The steering blades apply a constant force to the formation. The displacement of the blades is measured to offset the Bottom Hole Assembly (BHA) in the desired direction. The clamping force of the tool in the hole acts to stabilize the lower part of the BHA and remove unwanted vibration and instability from the drill bit. This significantly improves BHA response, borehole quality, ROP and bit life. Since the RSS has a full 3D capability, it can drill constant curvature boreholes in any direction.
The tool has been tested in wells in Texas, Louisiana, Oklahoma and the Gulf of Mexico. The results of these tests will be presented in detail. It is shown that BHA optimization can make a significant difference to the quality of directional holes drilled with a RSS. The data obtained during testing have, in fact, lead to an optimized BHA configuration which is unique compared with any other existing RSS. This optimized BHA configuration was determined from test runs in both point-the-bit and push-the-bit modes. Through the course of this exercise, it was shown that point-the-bit technology can provide superior borehole quality, improved Rate Of Penetration (ROP) and consistent Dog Leg Severity (DLS).
Finally, the improved performance and time saving obtained with this new RSS will be compared with offset data from directional wells that were drilled with conventional steerable motor assemblies.
A Physical Model for Stress Cages
Authors: Alberty Mark W. , McLean Michael R. 
Published: December 2007

Abstract
Well designs are constrained by the variation of both the pore pressure and fracture gradients throughout the depth of the well. Each hole section is designed such that the pressure profile within the hole at any time during drilling will not exceed the fracture pressure profile at any point throughout that section. The maximum pressures catered for in the design are invariably dictated by permeable formations with the highest pore pressure gradient. The casing depths are set to put behind pipe formations with too weak a fracture gradient to resist the planned pressure profile expected during drilling. This prevents a weak formation from failing and cross flow occurring between that failed zone and any high pressure permeable formations within the same hole section. The fracture gradient is typically determined by measuring the pressure at which losses begin to occur in the hole section and converting the downhole pressure into an equivalent mud weight. Most operators and mud companies have observed that the addition of some mud additives has influenced the pressure at which these induced losses begin. However, the use of those additives has been unreliable in many instances.
Recent work at BP has resulted in the development of a physical model that describes the mechanism that allows the fracture resistance to increase above conventional minimum horizontal stress through the addition of mud additives. These additives result in the formation of a "stress cage" which is a near wellbore region of high stress induced by propping open and sealing shallow fractures at the wellbore/formation interface. With the development of the physical model it is now possible to analyze the effects of different drilling practices upon the reliability and stability of those induced stress cages.
The development of stress cages is influenced by a number of properties including the diameter of the borehole, the width of fractures induced in a formation, the range of particle sizes which can be used as proppant in the fracture, the sealing properties of the mud, and the permeability of the formation. The successful implementation of the stress cage mechanism is dependent upon the use of appropriate constructive drilling practices and avoidance of detrimental practices which may destabilize the stress cages.
Gas Lift Optimization for Long-Term Reservoir Simulations
Authors: Wang Pengju , Litvak Michael 
Published: December 2007

Abstract
Although various gas-lift optimization algorithms have been proposed in literature, few of them is suitable for long-term reservoir development studies, which require the gas-lift optimizer to be highly efficient, flexible and powerful enough to handle complicated fluid flows and operational constraints, and have low impact on simulator convergences. This paper investigated methods to address these important issues.
The gas-lift optimization problem considered in this paper is to maximize the daily hydrocarbon production by selecting optimally the well production and lift gas rates subject to pressure and rate constraints in nodes of the surface pipeline network and to the amount of lift gas available. The problem is regarded as a well management problem in a commercial reservoir simulator capable of simulating multiphase compositional fluid flow in reservoirs, well tubing strings, surface pipeline network systems, and separation facilities. The problem is solved in selected iterations of a reservoir simulation time step.
This paper proposed a method for the described gas-lift optimization problem and investigated its performance against multiple existing methods. Case studies showed that the new method is capable of producing high quality results while requires less CPU time for optimization and has smaller impact on reservoir simulator convergence.
This paper also applied the concept of multiobjective optimization to smooth the rate oscillation between adjacent iterations by sacrificing a certain amount of oil production. In certain cases, this method reduces the simulation time significantly.
Case Study: Evaluation and Remediation of High-GOR Horizontal Wells
Authors: Frankenburg Amy , Hupp Douglas 
Published: December 2007

Abstract
This paper describes the integration of openhole well logs and memory production logging data to aid the evaluation and remediation of a horizontal well by understanding reservoir fluid contact.
This paper includes a case study of the techniques used to acquire and interpret three-phase flow in a North Slope horizontal well, procedures used to remediate the well, and their results. The example well was shut in as a result of the high gas production rate and uncompetitive gas/oil ratio (GOR) shortly after completion. The production logging data acquired with memory was utilized in combination with openhole log data to refine the reservoir fluid contact estimates. A refinement of the near-wellbore fluid picture (gas/oil/water) reduced the risk involved with the various remediation options enough to proceed. The remediation action chosen was a program to add perforations. This program was economically successful and resulted in the well being placed back on production as a competitive full-time producer with substantially reduced GOR and increased oil rates.
To fully evaluate the downhole flow contribution of the various zones within the reservoir, it was necessary to evaluate the three-phase flow in this horizontal well. Traditionally, this had been accomplished with coiled electric line. In the wells described in this case study, memory production sensors recorded both gas holdup (through optical probes) and distributed water holdup. These measurements allowed accurate identification of entry points of all three phases.
The techniques described in this paper have wide application for remediation of horizontal wells in mature fields.
Case History of Using an Integrated Asset Model for Depletion Planning of a Tight Gas Reservoir, Northeast Thompsonville Field, Jim Hogg and Webb Counties, Texas
Authors: Schott David W. , Abacioglu Yafes , Moran Mark J. , Stein Michael H. , Scattergood Joseph 
Published: December 2007

Abstract
This paper describes the results of a gas field development study that involved the integration of various technologies to determine how to lower field abandonment pressure, increase rate and reserves, improve profitability, and how to better manage the natural decline of the gas field. Subsurface and surface technologies were integrated. Part of the integration involved employing an integrated asset model. The integrated asset model (IAM) tool included a surface pipeline network simulator, coupled to wellbore models, reservoir inflow models, and material balance models for the entire field. This application addresses modeling of tight gas reservoirs with nodal analysis models in a manner that incorporates the transient aspects in the nodal analysis. The reservoir in this study had a high temperature, and thus water vapor was accounted for in the pressure drop calculations of both the wellbores and the surface pipelines. The modeling of compressors in the surface pipeline network model is also addressed. Modeling compressors with low suction pressure was found to be extremely challenging. Limitations and areas for improvement are discussed.
Facility modifications to increase gas production, profitability, and gas reserves were identified. Better management of individual wells routed to particular compressors is expected to increase gas recovery by lowering overall field abandonment pressure.
Integrated Seismic-Guided Characterization of a Carbonate Reservoir in Abu Dhabi, U.A.E.
Authors: Abbaszadeh Maghsood , Takahashi Isao , Suzuki Koichi 
Published: December 2007

Abstract
This paper presents a novel methodology for seismic-guided integrated reservoir characterization of a thinly bedded stratified heterogeneous carbonate reservoir, located offshore Abu Dhabi, U.A.E. The data sources include high-resolution log- and core-scale porosity, well test-calibrated layer permeability, and seismic attributes of AI (acoustic impedance) and Vp/Vs (ratio of P-wave to S-wave velocity), extracted from high-resolution 3D seismic data. A robust multivariate Gaussian approach is used to integrate these data types for improved 3D distributions of porosity, permeability, enhanced permeability and reduced uncertainty. It is shown that permeability can be tied to seismic Vp/Vs, based on a sound rock physics investigation.
Geostatistical conditional sequential simulations collocated with the seismic attributes and combined with a deterministic geological trend model are utilized to generate multiple realizations of porosity and permeability at both zone-scale and thinly bedded layer-scale. Porosity is modeled in 3D conditioned to seismic data, while permeability is modeled on layer-by-layer basis as a series of 2D stochastic distributions conditioned to seismic and collocated with porosity distributions. Permeability enhancement distributions are constructed from incremental ?kh over core-derived flow capacity (kh) at wells integrated with seismic attributes.
Comprehensive cross validation analyses at both reservoir zone-scale and layer-scale are performed with and without seismic to assess uncertainty in reservoir characterizations, and evaluate the value of seismic in improving reservoirs descriptions. The results indicate that overall uncertainty in porosity and permeability are reduced by 50% and 30%, respectively, when seismic information is integrated.
Design and Execution of a Successful Well Kill on the World's Longest-Running Blow-out
Authors: Bellis Chris J. , Bothwell Paul D. , Burke Lyle H. , Grace Robert D. , MacDonald Ron R. , McLellan Pat J. 
Published: December 2007

Abstract
This paper reviews the history of the world&#39;s largest running blowout as well as the integrated engineering based approach taken to define the blow-out mechanism and to ultimately kill and abandon the wells.
During 1916 cable tool drilling operations, Peace River Oils No.1 encountered an uncontrolled flow of salt water and gas at 345 m depth. The flow was estimated at over 30,000 bbls/d, ultimately the rig collapsed into the sinkhole and temporarily killed the surface flow. The rig was rebuilt in 1917, recovered the production casing, but again a blow-out could not be controlled and the well was left to flow 30,000 bbls/day of salt water into the Peace River. At the time of the project initiation, there was one relief well (1955), one attempted relief well (1982) and a lost well (1916).
The defacto well operator, the Alberta Energy and Utilities Board contracted an integrated team of professionals including well control engineers; geologists, drilling and completion engineers, geomechanics specialists and well operations specialists to evaluate the potential of effecting a permanent kill solution. This led to a primary recommendation to re-enter the 1916 wellbore via a flowing well operation to reach total depth and conduct a well kill.
The kill operation was complicated by having no production casing within the 1916 wellbore, shallow underground flows with multiple break-outs around the three wells, collapsed and parted casing in the 1955 well and entrained sour gas. The uncertainty of achieving access to the various wells to total depth and preparing for a wide range of potential well kill volumes and rates, were primary concern, as were the environmental constraints of operating on the unstable banks of the nearby Peace River.
Coiled-Tubing Deployment of Hydrajet-Fracturing Technique Enhances Safety and Flexibility, Reduces Job Time
Authors: McDaniel B. W. , Willett Ron , East Loyd , Rosato Jeff , Surjaatmadja Jim 
Published: December 2007

Abstract
Hydrajet fracturing, a relatively new stimulation technology for horizontal completions, has already proven successful in oil and gas wells across three continents. This multistage fracture stimulation method has primarily used jointed pipe to achieve hydraulic fracturing injection rates. The recent introduction of large OD coiled-tubing (CT) to the process has improved operating flexibility, reduced job time, and significantly enhanced health, safety, and environmental (HSE) performance. For some operations, it can also provide cost savings.
Before 2003, most CT-conveyed applications of this process typically were limited to hydrajet-assisted acid-squeeze injections, with only a few low-rate acid-frac treatments performed. By using larger-OD coiled tubing, operators have placed propped fracture treatments to approximately 8,000 ft measured depth (MD) at treating rates up to 10 bbl/min.
The use of a combined workstring consisting of jointed pipe connected to a surface string of CT can enable these multi-stage treatments to be placed in much deeper reservoirs, effectively doubling or tripling the depth capability of a CT-deployed treatment. For many applications this capability would provide the flexibility, speed, and safety inherent to coiled-tubing operations with a spool of only a few thousand feet, and jointed pipe would not be exposed to high treating pressures at the surface.
This paper reviews several field applications where coiled tubing was used to deploy hydraulic jet fracture treatments. One field case is compared directly to an earlier treatment in the same reservoir, which had been pumped through jointed pipe.
Saturation and Viscosity from Multidimensional Nuclear Magnetic Resonance Logging
Authors: Heaton N. J. , Minh C. Cao , Kovats J. , Guru U. 
Published: December 2007

Abstract
The last decade of nuclear magnetic resonance (NMR) logging has been dominated by T2 measurements and sparse sampling of polarization (differential spectrum) or diffusion (shifted spectrum) effects. Recent literature has expanded on the utility of NMR logging using T1 measurements to provide information on long time constants that are difficult or impossible to derive from T2 measurements using gradient tools. NMR logging modes have typically been designed to focus on a single specific NMR response, either very fast or very slow diffusion, or long T1 times, to identify either oil or gas. However, fluid properties can vary widely and often unpredictably downhole. A small number of NMR measurements that focus on just one NMR parameter may not provide sufficient information to identify and quantify fluid volumes, particularly when several different fluids are present. Achieving accurate fluid properties often requires data acquisition that simultaneously measures T1, T2, and diffusion contrasts. Inversion is most effective when all three NMR properties, T1, T2 and D, are obtained. We review the relative merits of T1, T2, and diffusion-based measurements in the light of petrophysics and instrumentation limitations. The relative merits of forward-model inversion and model-free analysis are discussed with reference to data sets recorded in a broad range of environments.