bluuebunny/crossref_metadata_2025_split huggingface dataset:
Aquifer Controls on Coalbed Methane Development in the Powder River Basin, Wyoming
Authors: Onsager P. R. , Cox D. O. 
Published: December 2007

Abstract
Development of coalbed methane (CBM) in the Wyodak-Anderson seams of the Powder River Basin, Wyoming, is one of the most active plays in the world. Compared to other CBM producing basins, the Powder River Basin subbituminous coal has relatively low gas content (20–50 scf/ton), but high permeability (100s of millidarcy to 1+ darcy). Because of the shallow depth, Powder River Basin CBM development is normally on 40- or 80-acre well spacing. Another significant difference between the Powder River Basin and other producing CBM basins is the fact that the coal seams of the Powder River Basin are overlain and underlain by large, thick aquifers that are essentially infinite-acting in nature. The degree of hydraulic connection between these aquifers and the coal is a critical factor in the economics of gas production from this play. Where the aquifers are well connected to the coal, water influx or leakance is high, leading to a nearly steady-state pressure environment that will deter efforts to dewater the coal and produce methane. Using reservoir simulation analyses and actual field data on gas and water production, this paper examines the effect of aquifer leakance on the producibility of the coal. Optimum well spacing in the Powder River Basin is shown to depend on having sufficient wells per section to lift the water that leaks into the coal from the aquifers. In fact, in some parts of the basin, aquifer leakance will maintain reservoir pressure high enough that it will curtail methane desorption and restrict ultimate gas recovery. Further testing and analysis to better characterize the aquifers and their connection to the coal is necessary.
The Lewis Shale, San Juan Basin: What We Know Now
Authors: Dube H. G. , Christiansen G. E. , Frantz J. H. , Fairchild N. R. , Olszewski A. J. , Sawyer W. K. , Williamson J. R. 
Published: December 2007

Abstract
In 1998, Burlington Resources (BR) initiated a study to characterize the Lewis Shale (Lewis) gas potential in the San Juan Basin (SJB) and optimize exploitation. Historically, most SJB production has been from naturally fractured, low permeability, Cretaceous sandstones (Dakota, Mesaverde, and Pictured Cliffs) or from the prolific Fruitland Coal. In the past, the Lewis, which lies between the Mesaverde and Pictured Cliffs Formations, was completed in only the few wells where large Lewis flow rates were encountered while air-drilling for deeper targets. However, the Lewis lies behind pipe in thousands of existing wells across the SJB. In a large number of these wells and in new Mesaverde/Dakota wells, the Lewis can be completed. The BR program includes performing geological, petrophysical, reservoir, stimulation, and production data analysis. From this data, reservoir characterization, completion optimization, and forecasting models were developed that indicate commercial Lewis potential through much of the SJB in both new and existing wells. Furthermore, the Lewis is more accurately characterized as a sandy siltstone, rather than a true shale such as the Devonian or Antrim Shale.
Benchmarking of Restimulation Candidate Selection Techniques in Layered, Tight Gas Sand Formations Using Reservoir Simulation
Authors: Reeves S. R. , Bastian P. A. , Spivey J. P. , Flumerfelt R. W. , Mohaghegh S. , Koperna G. J. 
Published: December 2007

Abstract
Studies by the Gas Research Institute have revealed that improved methods are needed to cost-effectively identify high-potential restimulation candidate wells. Subsequent research has had the objective of developing such methodologies, and testing them in the field. The techniques being investigated include production statistics, virtual intelligence, and type-curves. For various reasons, field activities have been slow to implement, limiting the feedback needed to fully test each candidate selection method. Therefore a reservoir simulation study was performed to test the methods. The simulation field model consisted of four reservoir layers of variable properties. Wells were drilled in three rounds over a 12-year period (120 total wells). Completion intervals were varied for each well, as were skin factors for individual layers. Before providing the data to the project team for analysis, noise was added. These model features and noise were incorporated into the exercise to best replicate actual field conditions. Restimulation potential was established by "restimulating" each well in the model and observing the incremental production response. Application of the various candidate selection techniques, and comparing the results to the known answer, has yielded several important conclusions. First, simple production data comparisons are not effective at identifying high-potential restimulation candidates; better producing wells tend to be better restimulation candidates. Virtual intelligence techniques were the most successful, correctly identifying over 80% of the theoretical maximum available potential. The type-curve technique was not as effective as virtual intelligence, but still achieved a 75% candidate selection efficiency.
Qualification of a Nonintrusive Multiphase Flow Meter in Viscous Flows
Authors: Atkinson D. I. , Bérard M. , Ségéral G. 
Published: December 2007

Abstract
New requirements have recently appeared for accurate and reliable flow rate measurements in various operational areas where viscous fluids are produced. Heavy oil as produced in Venezuela, Confederation of Independent States (CIS), Brazil, Angola and China and lighter oil emulsified with large water cuts (worldwide) present new challenges to multiphase metering.
The compact, cost-effective multiphase meter described in this paper is intended to replace large, costly test separators designed for heavy oils. The meter is non-intrusive and combines a classical venturi to measure total mass flow rate and a dual energy gamma-ray composition meter to measure oil, water and gas fractions. A benefit of this compact design is that the meter can be switched from one well to another and provide robust, consistent flow rate measurements without any flow recalibration.
According to published single-phase flow literature, liquid viscosity plays an important role in meter performance. Oil companies are becoming increasingly aware of these problems and want more evidence that a multiphase meter will perform regardless of fluid properties.
To qualify the multiphase meter in high-viscosity flows, we conducted comprehensive flow loop tests in Venezuela. The challenge was to gain a solid understanding of viscosity effects even in the presence of large amounts of gas, and for the entire operating envelope of the meter. These test results have been used to refine the meter interpretation model to maintain the metering accuracy in these conditions. The interpretation includes a mixture viscosity model based on the dead-oil viscosity; for permanent monitoring and periodic testing, the effluent viscosity variations are updated when pressure, temperature or water cut is changing.
To demonstrate that the specified measurement accuracy was achieved up to the highest viscosities tested (several thousand centipoise), the meter was field tested in comparison with a test separator. We present the results of 54 jobs.
Until recently, the only multiphase meters available to measure viscous oil flowing with gas were intrusive. Positive displacement meters, such as oval gears, twin helical screws or vane types, were used to measure the total gas-liquid volume flow rate. These meters are very sensitive to severe slugging in the upstream pipeline and prone to mechanical damage from produced solid particles.
The lightweight, small-footprint meter described here solves these problems. Consistent flow rate information can be obtained even when the meter is switched from well to well. Fluid property or flow regime changes do not affect the flow rate measurement.
Rate Effects on Centrifuge Drainage Relative Permeability
Authors: Skauge Arne , Poulsen Susanne 
Published: December 2007

Abstract
Estimation of oil drainage relative permeability can be made from centrifuge measurements either by single-step or mul-tistep experiments. This paper compares relative permeability calculated from the two centrifuge methods to data from long core gravity drainage gas injection.
Simulations of centrifuge single-step drainage experiments at varying rpm have been performed, with independent measured capillary pressure included. The relative permeability curves hereby estimated seem to be rpm (rotations per minute) dependent.
The paper gives recommendation for a minimum or critical Bond number for which capillary pressure can be ignored in drainage relative permeability calculations. Simulation of long core gas gravity drainage experiments supports the results of the single-step centrifuge drainage at low rotational speed.
The multi-step centrifuge experiments have the benefit of simultaneous calculation of both relative permeability and capillary pressure. However we find the multi-step technique to overestimate capillary pressure and underestimate oil relative permeability. These results come from comparing with direct capillary pressure measurements and relative permeability derived from long-core or single step centrifuge data corrected for capillary pressure.
A Hybrid Streamtube Simulator Using A Semianalytical Method
Authors: Baek Munseok , Hewett Thomas A. 
Published: December 2007

Abstract
A hybrid streamtube simulator is developed using a semianalytical method. This hybrid simulator applies to steady-state, incompressible, two-phase, field-scale problems, where the effects of gravity can be neglected. The underlying idea of the hybrid streamtube method is to decouple a large 3-D problem into multiple cross-sections along areal streamtube bundles. Using the calculations of cross-sections, the areal recovery is computed. This method is based on the assumption that the effects of a changing mobility field can be accounted for by using fixed streamtube geometries with updated flowrates. In each cross-section the semi-analytical method is applied, which uses the single-phase pressure distribution and the 1-D Buckley-Leverett solution along the streamtube. The distribution of pore volume along each streamtube is calculated by using the Time-Of-Flight method. This information and the pressure solution are used to calculate oil recovery by the semianalytical method. Unlike previous hybrid methods, the simulator developed uses a streamtube method in each cross-section. Due to the simple calculations and small arrays the method developed shows a very fast calculation speed compared to a conventional finite difference simulator (ECLIPSE), a streamline simulator (3DSL) and another streamtube simulator (STUB3D). The simulator developed shows good agreement with other methods for an end-point mobility ratio range from 1 to 50. The hybrid streamtube method (HST) was faster than the updated streamline method (3DSL) by factors of 1 to 3 orders of magnitude, and the conventional finite difference method (ECLIPSE) by factors of more than 3 orders of magnitude.
Crack Tip Plasticity: A Different Approach to Modelling Fracture Propagation in Soft Formations
Authors: Martin A. N. 
Published: December 2007

Abstract
Over the last 15 years or so, the numerical simulation of hydraulic fracturing has improved beyond recognition. Considerable time and effort has been spent on the production of these models and on their verification with field trials. In spite of their differences, these models still employ, to a lesser or greater extent, the same basic theory of fracture propagation - first put forward in the 1920’s and used in the original 2-D fracture models – known as Linear Elastic Fracture Mechanics, or LEFM. Although the various organisations producing fracture propagation models have extensively modified the original LEFM theory, mainly to allow for the effects of non-linearity at the crack tip, the original assumptions of LEFM still hold true. Failure is by brittle fracture, with no significant plastic deformation of the rock – even at the fracture tip. This assumption is probably valid for most of the formations fractured by the industry today. However, an increasingly important sector of the industry is now stimulating very soft, ductile formations, where the assumptions of linear strain and no significant plastic deformation are not reliable. Fortunately, LEFM is not the only way to model fracture propagation. The Crack Tip Plasticity (CTP) method assumes a fracture tip of finite radius, with a zone of plastically deformed material around it. This plastic zone acts to absorb extra energy from the fracturing fluid, making it harder to propagate fractures through formations with significant plastic deformation. This in turn means that, for a given ductile material, fractures will be smaller and less conductive than those predicted by LEFM. An understanding of CTP could help predict how much smaller the fracture really is, and could also help explain why LEFM-based fracture simulators cannot adequately model very soft formations.
A Model for Sand Screen Running on Marnock: A Horizontal, Near-HPHT Well Development
Authors: Swanson Bruce , Inglis Charles , Reed David 
Published: December 2007

Abstract
The Marnock field, situated in the Central North Sea, is the first development in the North Sea to combine the challenges of near HPHT conditions (9100 psi and 310 F) with a horizontal sand screen completion. Once completed, the wells have proved to be highly productive with production rates up to 120mmscf/day. However, well completion, and especially installation of sand screens, has proved problematic with two out of the four wells completed with screens off-bottom
This paper describes the development of an empirically based model compiled from information gained during the drilling of reservoir sections and screen running on four Marnock wells. The model represents the accumulated learning over the four well development and was developed to capture learning as well as provide a means of assessing the risk of well designs failing to get screens down during well planning. The basis of the model is an analysis of the 15 factors considered relevant to creating a wellbore in which screens will successfully be run to bottom - these included aspects such as hole tortuosity, hole length and maximum angle. This collected data set is then used within a set of rules based on the well construction team’s experience. This provides a basis for critique of new well designs and a means of assessing the impact of changes to the design.
Details of the model are provided in the paper together with examples from the field development which illustrate how the model has been used. The paper also presents how the model has been used to understand sensitivities and identify where improvements can be made to a well design to improve the probability that screens can be run successfully. The technique used to develop the model will be applicable to other multivariable complex drilling and completion problems.
Comparison of Booking Methodologies for Production Sharing Agreements and Service Contracts
Authors: Reiter Doris F. , Bolling John D. 
Published: December 2007

Abstract
Concessions were predominantly used up until the late 1960s, when Production Sharing Agreements- or also called Production Sharing Contracts (PSA or PSC) - came into existence. They provide an alternative to concessionary systems for those foreign countries, whose constitutions stipulate that all mineral rights lie with the state, but who do not wish to exploit their hydrocarbon resource base on their own. Regulations, which govern the external oil and gas reserves reporting, give a high degree of latitude as to how a company interprets and applies those rules to reserve bookings. From a financial point of view, PSAs and concessions are quite similar; they are distinctly different though from a philosophical point of view. The concession owner holds title to the hydrocarbons in place, whereas in the PSAs the entitlement is not transferred to the contracting party. But it is the entitlement to reserves, which ultimately provides the right to book reserves. For concessions, the reserve booking procedure is very clear, since the concession owner owns the mineral rights, whereas in case of PSAs the situation gets much more complicated. This paper explores different types of such agreements. It further discusses the question, whether reserve bookings for internal and external reporting purposes are permissible under certain kinds of arrangements and what, if any, volumes can be booked. Two methods are applied: The working interest method and the economic interest method. The hazard in using the working interest method, lies in the fact, that the government production entitlement would be treated as a tax expense from the contractor’s point of view. But the host government or their representing oil institution will book their share of profit oil/gas as well, leading to reported gross reserves exceeding those ultimately produced. It would be preferable if oil companies strive to apply the economic method uniformly. The economic interest represents the actual barrel entitlement and thus is comparable to reserve numbers from concessions or leases.
As the investment community places great significance on reported volumes to gauge the company’s financial strength and future growth potential, it would be desirable to achieve a higher degree of consistency in reserve booking industrywide. Internally the company will profit by improving benchmarking in portfolio management decisions.
Geostatistical Modeling of Facies and Fractures of the San Juan Formation and Reservoir Modeling for Delineation of Orocual Field, Venezuela
Authors: Porjesz Róbert , Vargas Marielis , Guerini Agostino , Márquez Pascual , Melendez Luis , Smith Richard W. 
Published: December 2007

Abstract
The Orocual field is located in northern Monagas State of Venezuela and is owned and operated by Petroleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela. This paper presents the results of the geological and geostatis-tical modeling aspects of an integrated study for the San Juan Reservoir in Orocual Field, Eastern Venezuela. The objective of this work was to establish a static model to be used in dynamic modeling to determine development potential, risk, and hydrocarbon reserves. Special interest exists in untested but highly prospective areas.
A recently acquired 3-D seismic volume was integrated with a detailed core based sedimentology study used to define the depositional environment and facies connectivity. Based on this description, the San Juan Formation is subdivided into 3 major sedimentological units: Lower, Middle and Upper. A stochastic method was used to quantify model uncertainty. The fine grid geostatistical model was up-scaled to provide facies consistency for reservoir modeling. The prediction of heterogeneous fractured reservoir was added to the complexity. Numerical simulation was performed and will be discussed.
A Method for Enhancing the Vertical Resolution of NMR Logs
Authors: Sigal R. F. , Miller D. L. , Galford J. E. , Cherry R. , Day P. I. 
Published: December 2007

Abstract
The vertical resolution of continuous, multi-frequency NMR logs largely depends on the length of the stacking interval. Several factors determine the stacking length, such as the number of Carr-Purcell-Meiboom-Gill (CPMG) echo trains that are stacked to improve signal-to-noise ratio, the time interval between individual CPMG events, and logging speed. Standard processing requires stacking of phase-alternate pairs of CPMG events to remove "ringing" contributions. "Ringing" lumps together the non-formation signals present in the acquired CPMG echo trains. This requirement imposes a minimum stacking length for any combination of CPMG sequences. If additional stacking is required to improve signal-to-noise, the simplest filter design requires multiples of the minimum stacking interval. This may produce a better signal-to-noise-ratio, and a larger degradation of vertical resolution than is necessary.
An alternative single echo-train offset removal method (SETOR) has been developed to improve the vertical resolution of NMR logs. In this method the ringing contribution is estimated and removed from the individual CPMG echo trains before stacking. In many cases, results with significantly better vertical resolution, compared to the standard processing, can be obtained because the minimum stacking interval is reduced to a single CPMG event. This allows the stacking interval to be tailored to a desired signal-to-noise ratio. The application of the technique is particularly important for the latest nine-frequency tools that are capable of logging at greater speeds than previous tools.
The theory and current implementation of SETOR is described. In addition, a log example is presented to demonstrate how the method can significantly improve vertical resolution. In this example, stacking length could be reduced from 8.5 feet to 3 feet producing a porosity log that closely matches the finer scale features of a conventional density porosity log. Station data are also presented to help validate the method.
A New Method for Assessing the Impacts of Small-Scale Solvent Supply Variations within the Prudhoe Bay Miscible Flood
Authors: Weaver J. W. , Ra J. W. 
Published: December 2007

Abstract
As the Prudhoe Bay Miscible Gas Project (PBMGP) approaches its fourteenth year of operation, the water alternating gas (WAG) flood is facing new challenges. These challenges typically involve projects that lead to small miscible injectant, or solvent, supply variations. For example, upgrades of the surface facilities can increase the solvent supply available to the PBMGP. Conversely, undertaking new EOR projects or supplying solvent to non-Prudhoe Bay projects will reduce the supply available to the PBMGP.
To accurately assess these projects, a new methodology was developed for forecasting enhanced oil recovery (EOR). This methodology provides increased ease of use and greater reliability in assessing small changes in solvent supply when compared with direct application of large-scale models.
Full-field modeling of miscible injectant (MI) allocation and enhanced oil recovery for the Prudhoe Bay WAG flood is currently performed with large scale-up models. While these models are excellent for evaluating large, full-field decisions related to miscible injection at Prudhoe Bay, they can yield ambiguous results when used to evaluate projects that cause small solvent supply perturbations. The difficulty in resolving the impacts of small incremental projects is a common weakness of large-scale reservoir models.
Through analysis of numerous Prudhoe Bay full-field simulations of large variations in the MI supply, it was found that a two-component analytical equation was excellent for fitting the character of the cumulative EOR impact. The logarithmic function represents the ultimate EOR impact of a change in MI supply, whereas the Weibull function represents the EOR oil rate acceleration (or deceleration) component. The optimum coefficients for the composite analytical equation were found through regression of large-scale simulation results.
This paper documents the methodology used to create the analytical equation as well as the equation's successful testing. The methodology could be applied to other large-scale models that suffer from an inability to accurately evaluate small incremental projects.