bluuebunny/crossref_metadata_2025 huggingface dataset:
Applications of a New Multiple Sensor Production Logging System for Horizontal and Highly-Deviated Multiphase Producers
Authors: Chace David , Wang Jianrong , Mirzwinski Roman , Maxit Jorge , Trcka Darryl
Published: December 2007

This paper focuses on the first applications of an improved, second-generation multiple sensor production logging system designed for use in horizontal and highly deviated multiphase producers. The system integrates several key measurements to provide a comprehensive analysis of well performance under a variety of conditions and flow rates. An expanded and improved 2-dimensional capacitance array is used to define flow regime and measure 3-phase holdup, velocities and flow rates. A new 3-detector pulsed neutron instrument provides an independent measurement of water velocity, 3-phase holdups, and formation water saturation. Auxiliary sensors include an acoustic transducer and distributed temperature sensors useful for gas entry, liquid entry, and behind-casing channel identification. A quartz-pressure gauge measurement is recorded which is also useful in mechanistic models of multiphase flow.

While a brief description of the system components will be provided in order to familiarize readers with the measurement concepts, this paper will concentrate on field examples from the Middle East that demonstrate the first use of the improved logging system in horizontal openhole multiphase producing wells. Determination of multiphase holdups, cross-wellbore velocity profiling, and production inflow profiling is demonstrated. Openhole logs are also shown, including resistivity image data, which clearly differentiate the inflow points as producing bed layers or conductive fractures.
Three Successful Large-scale Field Tests of Crosshole Electromagnetic Tomography Technology
Authors: Zeng Wenchong , Zhao Wenjie , Wilt Michael
Published: December 2007

A leading edge for the applied technological development of geophysics today — crosshole electromagnetic (EM) tomography technology, is an extremely challenging research topic. Its principal technological objective is to realize the direct measurement of the interwell resistivity in order to offer a two-dimensional, even three-dimensional resistivity image reflecting formation structure, reservoir property and the distribution of oil, gas and water between wells. So it not only is a momentous development of the conventional logging technology, but also will revolutionize the reservoir research. Shengli Oilfield (or SPAB) has cooperated with EMI to conduct the application study of the crosshole EM tomography technology for many years. Recently five large-scale industrial tests of the crosshole electromagnetic tomography were conducted successfully in three pairs of wells in Gudao and Chengdong oilfields attached to Shengli Oilfield. The desired results are achieved in three tests. Not only the stability and reliability of the instrument performance are proven, but also it is the first time in the world that a complete measurement data with good repeatability and high accuracy has been obtained when the interwell distance is up to 433.6 m for openhole to openhole and 147.19m for openhole to steel-cased hole. The resistivity image obtained from the inversion has provided a good geological result in analyzing the interwell hydrocarbon and sand body distribution. These achievements indicate that great progress has been made in the industrialization of the crosshole EM tomography technology.
Waterflood Management: A Case Study of the Northwest Fault Block Area of Prudhoe Bay, Alaska, Using Streamline Simulation and Traditional Waterflood Analysis
Authors: Grinestaff G. H. , Caffrey Daniel J.
Published: December 2007

This case study of a complex multiple-Zone waterflood in Prudhoe Bay, Alaska, focuses on the basics of waterflood management that are often overlooked. Evaluation of injection well conformance, flood front behavior, and reservoir description, followed by improved injection well management resulted in dramatic improvements in waterflood performance.

Assurance of waterflood performance requires an integrated approach and accurate performance predictions. The performance of the Northwest Fault Block (NWFB) waterflood was analyzed with traditional decline curves, Hall plots, and a thorough review of well histories to ascertain that it was under performing. A high-resolution 3-D streamline model proved to be the simulation of choice to answer regional and individual well performance questions for this complex waterflood. After achieving a history match for each of the 200+ wells, streamline modeling provided accurate results of vertical and area wide sweep inefficiencies that were later verified by horizontal drilling. Water cycling was quantified by streamline simulation and injection reduced by 30-40%, resulting in increased production and cost savings. Expansion of the waterflood into the gravity drainage area was stopped. Most importantly, bypassed oil is being developed through an aggressive injection well replacement program.

These promising results were achieved by a multidisciplinary team that focused on understanding micro and macro scale reservoir mechanisms. This holistic understanding of mature waterflood behavior, was achieved with a thorough understanding of injection well behavior and streamline simulation at a detailed scale to match each wells performance.
Application of Radial Flow Theory and PLT Surveys to Determine Reservoir Pressure and Wellbore Conditions for Gas Reservoirs
Authors: Wang Shie-Way
Published: December 2007

This work presents a new method to determine average reservoir pressure, change of wellbore condition, and skin factor based on (1) pseudo steady state or steady state theory, and (2) flowing bottom hole pressure and production rate obtained from production logging tool surveys for a single or stacked-pay reservoir. This new method requires two production rate perturbations at 24 hours apart and is equally applicable to oil reservoirs. Four examples are provided to demonstrate how to apply this new method. A single reservoir with multi-layers in vertical communication was used in examples 1 to 3. A stacked-pay reservoir was used in example 4, which consists of six sand-shale sequences with different net pay, permeability, and skin factor for each sand. Excellent agreement is observed in all examples between calculated reservoir pressure and skin factor and those obtained by reservoir simulation.
Gas-Condensate Well Test Analysis With and Without Relative Permeability Curves
Authors: Penuela Gherson , Civan Faruk
Published: December 2007

Based on an analytical analysis of the steady-state theory and its application to well test interpretation in gas-condensate reservoirs, two simplified models are proposed when relative permeability curves are not available. They allow the reservoir engineer to have relative permeability curves as functions of bottomhole pressure from constant composition experiments. Step-by-step procedures explained in the paper rely on the suitability of the steady-state assumptions. Comparisons are made using actual field data and discussions on applicability are also presented. One of the methods is applicable when very low capillary number can be assumed, and immiscible relative permeability curves can be used for pressure transient interpretation. This method is recommended to be used in pressure buildup data analysis. The other proposed method is recommended for pressure drawdown data analysis and is based on the assumption that miscible flow regime controls the fluid flow in the near wellbore region. It is concluded that, although it depends on several factors, miscible relative permeability curves are generally good approximation for pressure drawdown data analysis.

An additional method is also discussed. It relies on the ability to simulate properly the near-wellbore fluid flow with accurate fluid and flow models. Using output data from a compositional simulator, it was shown that it is possible to numerically model fluid bank impairment, while analytically, it is possible to obtain reservoir properties, usually shadowed in current methods for condensate buildup.

The proposed numerical method requires detailed information and can be impractical to apply at early stages of gas-condensate production. On the other hand, the two analytical methods are shown to give good estimates of permeability, mechanical skin factor and reservoir initial pressure at early stages when relative permeability data are not available or are not sufficiently reliable.
Matching Production Rates From the Saih Rawl and Barik Gas-Condensate Fields Using State-of-the-Art Single Well Reservoir Simulation Model
Authors: Skaar Rolf G. , Walpot Kimberly S. , van der Post Niko
Published: December 2007

This paper describes how the initial 6 months of production data from the Barik and Saih Rawl gas condensate fields was matched in state of the art single-well-simulation models. A total of 10 wells were matched and very good agreement between the simulated and actual data was obtained. Detailed results are presented for 3 of the 10 wells. The results from reservoir simulation also agreed favourably with results from analytical well test analysis. The production wells in the two fields described have been stimulated with either single or multiple, propped hydraulic fractures.
Impact of Rock Plasticity on Hydraulic Fracture Propagation and Closure
Authors: Dam D. B. van , Papanastasiou P. , de Pater C. J.
Published: December 2007

We performed scaled laboratory experiments of hydraulic fracture propagation and closure in soft artificial rock and outcrop rock samples. We also performed numerical simulations of the fracture behaviour in plastic rocks, using independently measured rock properties. The simulations aided us in interpreting the measurements and extrapolating the results to field scale. Plasticity induces a larger width for a given net pressure, compared with elastic rock. However, the pressure to propagate fractures is only marginally increased and in the case of the laboratory tests was actually lower than expected from elastic behaviour. The most dramatic effect of plasticity is that closure is much lower than the confining stress due to strong stress redistribution along the fracture.
Modeling of the Acidizing Process in Naturally-Fractured Carbonates
Authors: Dong C. , Zhu D. , Hill A. D.
Published: December 2007

When a naturally fractured carbonate formation is treated with acid at pressures below the fracturing pressure, the acidizing process will likely be different from either a matrix treatment or an acid fracturing treatment. Our previous experimental study shows three kinds of acid etching patterns after acidizing naturally-fractured carbonates and also illustrates their relationships with the fracture properties and acidizing conditions. Based on the experimental observations, a mathematical model of acidizing naturally-fractured carbonates has been developed. The model includes bulk solution transport, acid transport and reaction, and the change of fracture width by acid dissolution. A new approach was used to treat leakoff acid and acid-rock reactions at the fracture walls. The new acidizing model for numerically generated rough-surfaced fractures predicts the same kinds of acid etching patterns and the same relationships between acid etching patterns and the fracture width, surface roughness and leakoff rate as observed in experiments.
Development of a Type Curve to Locate Partial Blockages in Gas Flowlines
Authors: Liu Liangjian , Scott Stuart L.
Published: December 2007

As exploration and production operations move into deeper waters, producers are faced with new flow assurance challenges. One problem associated with deepwater production is the deposition of paraffins, asphaltenes, hydrates, and scale within the pipeline. These depositions form partial pipeline blockages that reduce flow capacity and may ultimately put the subsea flowline at risk. Pigging and other intervention techniques can be used to deal with this problem. This paper develops a method for locating partial gas pipeline blockages and estimating their size. This method can be used to provide important information for monitoring chemical inhibition programs, scheduling pigging, assessing risk for pigging and planning other intervention procedures.

The type curve model is based on the pressure transient analysis of a shut-in test. It can locate the blockage when the blockage size (represented by a blockage factor) has been determined by the backpressure technique. A new average pressure model has also been developed. This method can also be used to locate a partial blockage by examining differences in the average pressure that is measured when a flowline is shut-in at both ends.
Critical Flow Rate for the Buckling of Nonrotating Drillpipe Conveying Fluid in Vertical Holes
Authors: Zhang Qun , Miska Stefan , Kuru Ergun , Azar J. J.
Published: December 2007

A new mathematical model has been developed to investigate the effect of incompressible drilling fluid hydraulics on the buckling behavior and lateral vibration of non-rotating drill pipe in a vertical hole. Dimensional analysis has been incorporated to generalize the solution. The method of Fourier series is utilized to obtain the desired solution.

Several numerical examples are provided to determine the critical flow rate that results in buckling under various conditions of pipe under tension, compression, or compression in the lower portion and tension in the upper. For each of the above cases the following scenarios have been studied: (1) fluid flowing downward in drillpipe; (2) fluid flowing upward in annular space; and (3) fluid flowing downward in drillpipe and upward in annular space simultaneously. The influence of fluid density is also investigated.
Modeling Dependencies Between Geologic Risks in Multiple Targets
Authors: Delfiner Pierre
Published: December 2007

A single-target prospect can be characterized probabilistically by two elements, the risk or probability of success, and the distribution of reserves given success. But there is no obvious way of combining the results of multiple targets into a single representative assessment.

This paper presents a simple approach for aggregating multiple targets for the purpose of prospect ranking. Reserves given success are assumed independent and the novelty lies in the modeling of dependencies between geologic risk factors. Although interdependence can be represented by conditional probabilities, the selection of these values is a problem for most explorationists. In this paper a more practical method is proposed. A matrix is completed for multiple targets specifying which geologic factors are common and which are independent. An outcome tree with dependent targets is created and the probability distribution of aggregate reserves is determined either analytically or by Monte Carlo simulation.

A case study with six targets illustrates the method. Dependencies reduce the probability of at least one success from 92% to 65% and the number of possible outcomes from 64 to 25. This allows a useful grouping by development cases. The method can be used for stacked reservoirs or portfolio analysis.
Alternative Approaches to Modeling Risks in Prospects with Dependent Layers
Authors: Stabell Charles B.
Published: December 2007

A main challenge for wildcat risk and resource assessment of prospects with complex, multiple layers and compartments is handling explicitly and consistently both risk and volume dependencies. This paper compares and contrasts three main alternative approaches to modeling risk dependencies: A complete enumeration of outcome probabilities, a bottom-up approach that aggregates risks using explicit shared risk estimates, and a top-down approach that generalizes the 2-level marginal play, conditional prospect risk model to a 3-level model with a conditional segment level risk. We consider assumptions, data needs and ease of use of the different approaches using illustrative cases and applications.
Horizon Attributes and Fracture-Swarm Sweet Spots in Low-Permeability Gas Reservoirs
Authors: Hart B. S. , Pearson R. A. , Herrin J. M. , Engler T. , Robinson R. L.
Published: December 2007

Horizon attributes, i.e., attributes that numerically describe geometric characteristics of interpreted horizons from conventional (i.e., p-wave) 3-D seismic volumes, hold considerable potential for identifying fracture-swarm sweet spots in low permeability reservoirs. Typically, these attributes (e.g., dip, azimuth, and curvature) are used to define subtle faults that are near the limit of seismic detectability. These subtle structures can play important roles in compartmentalizing conventional reservoirs. However, in low permeability gas reservoirs where fracture permeability is critical, these same attributes can be used to define high-permeability fracture swarms. We illustrate this point with three case studies, two clastic the other carbonate, from the San Juan Basin area of northwestern New Mexico. The Paradox Formation is a Pennsylvanian age low permeability carbonate reservoir. At Ute Dome Field, production characteristics indicate that fractures are the main control on gas production from these carbonates. Comparison of horizon attributes from this level with production data shows that these attributes are defining high-permeability fracture swarms associated with faults. The Mesaverde Group consists of Cretaceous age clastics and is a tight reservoir in the Blanco Field. Again, horizon attributes (including curvature attributes) can be used to define fault-related fracture swarms that will produce at higher rates than surrounding areas. The Dakota Sandstone is another Cretaceous tight gas sandstone. A map of horizon dip in one area shows a trend that is associated with anomalous production from two wells. However, these two wells cannot be described as "sweet spot" wells because their production is not anomalously high. These observations indicate that development drilling plans for low permeability reservoirs should take into account geologic heterogeneity that can be associated with fracture swarms. Undrilled fracture swarms should be targeted to produce high-rate wells. On the other hand, offset wells should specifically avoid drilling into previously tapped fracture swarms to avoid drainage interference. Other factors that need to be considered are: a) the orientation of the fractures with respect to in-situ stress directions, and b) lithologic (i.e., stratigraphic) control on fracture density.
A New NMR Method of Fluid Characterization in Reservoir Rocks: Experimental Confirmation and Simulation Results
Authors: Freedman R. , Sezginer A. , Flaum M. , Matteson A. , Lo S. , Hirasaki G. J.
Published: December 2007

A new magnetic resonance fluid (MRF) characterization method for fluids in porous rocks has been developed. The method uses suites of spin-echo measurements that can be acquired in the laboratory or by a nuclear magnetic resonance (NMR) logging tool. In general, the data suites consist of spinecho measurements with different echo spacings, polarization times, applied magnetic field gradients, and numbers of echoes. These measurements are sensitive to the viscosities and molecular diffusion coefficients of the fluids and therefore provide the information needed for fluid characterization.

The MRF method is based on the inversion of a general multifluid relaxational model that describes the decay of the transverse magnetization in porous rocks containing reservoir fluids. In its most general form, the relaxational model consists of separate contributions to the measured spin-echo signals from all of the fluids that can be present in reservoir rocks; i.e., brine, oil, gas, and oil-base mud filtrate (OBMF), including mixtures of gas dissolved in oil or OBMF. A key ingredient in the multifluid relaxational model is a new phenomenological microscopic constituent viscosity model (CVM) for hydrocarbon mixtures that links diffusion-free relaxation and molecular diffusion in crude oils. The CVM significantly improves the robustness of the inversion so that accurate fluid characterization is possible even when the brine and crude oil T1 and T2 distributions overlap one another. We present experimental results on live and dead hydrocarbon mixtures and crude oils that confirm the validity of the CVM.

The results of a Monte Carlo simulation for a model carbonate formation containing brine, crude oil, gas, and OBMF demonstrate the robustness and accuracy of the inversion. Monte Carlo simulations conducted for different types of rocks containing different amounts and types of fluids demonstrate that the inversion provides quantitative estimates of total porosity, fluid saturations, fluid volumes, bulk volume irreducible water, crude oil viscosity, hydrocarbon-corrected permeability, crude oil T1 and T2 relaxation time distributions, crude oil diffusion coefficient distributions, brine T2 distributions, and apparent brine T1/T2 ratios.

The MRF method was also tested in the laboratory on partially saturated Berea 100 and Indiana limestone rocks containing brine and oil. The water saturations estimated from the NMR data by inversion of the multifluid relaxational model are shown to agree well with the water saturations that were independently estimated from differential weight measurements. The oil viscosity estimates are also shown to be in good agreement with the known viscosity of the oil.
Imbibition Processes in Fractured Chalk Core Plugs with Connate Water Mobilization
Authors: Nielsen C. M. , Olsen D. , Bech N.
Published: December 2007

A displacement process in a chalk core plug with an induced axial fracture uses the fluid system H2O-D2O-n-decane. Initially the plug contains a mixture of D2O and n-decane with oil saturation equal to 88 %. The plug is flooded with H2O. The displacement process is monitored by NMR with a chemical shift technique enabling spatial resolution of the H2O and oil signals. The D2O component is not directly detected, but is calculated from the difference between the actual signal intensities and the signal intensities in a situation where the pore space is completely saturated with H2O and oil.

H2O-D2O-oil constitutes a partly miscible fluid system which is an analogy to the injection water-formation water-oil system of a hydrocarbon reservoir under waterflooding.

The injected H2O traverses the sample as a well-defined front together with capillary uptake from the fracture plane. Ahead of the H2O front the D2O of the sample is mobilized and travels as a bank in front of the H2O. Though the initial concentration of D2O is only 12% the D2O concentration reaches 50 % at the bank.

The experiment was simulated by means of ECLIPSE with a fair match of the displacement process.

The injected H2O has only made limited contact with the produced oil of the sample. In case of chemical EOR processes connected to waterflooding of hydrocarbon reservoirs a similar displacement situation could seriously affect the efficiency of the EOR process.
Reservoir Engineering Analysis of Microbial Enhanced Oil Recovery
Authors: Bryant Steven L. , Lockhart Thomas P.
Published: December 2007

We assess processes for enhancing oil recovery by means of microbes (MEOR) from the perspective of reservoir and reaction engineering. In this work, MEOR implies recovering incremental oil by means of increased displacement and/or volumetric efficiency; it does not include well stimulation treatments. MEOR processes address the same physical parameters as chemical EOR processes such as surfactant flooding, polymer flooding, alkaline flooding, etc. They are hence subject to the same technical difficulties: identifying and locating the target oil; retention, dissipation and consumption of chemicals in the formation, etc. The essential difference between MEOR and chemical EOR resides in the method of introducing the recovery-enhancing chemicals into the reservoir.

An examination of the literature shows that MEOR generally does not recover as much remaining oil in place as other chemical EOR processes, either in the laboratory or the field. Efforts to explain this difference are severely limited by the lack of quantitative measures of microbial performance (reaction rates, stoichiometry, required product concentrations, etc.) It is possible, however, to demonstrate quantitative relationships between microbial performance, reservoir characteristics, and operating conditions (well spacing, injection rates, residual oil saturation, etc.).

We conclude that MEOR is potentially a "high risk, high reward" process, depending on whether it can use residual oil as an in situ carbon source for the production of recovery-enhancing chemicals. The reward in this case is that the difficulty and the logistical costs of implementing the process would approach those of implementing a waterflood. The high risk is associated with the many and severe performance constraints that a microbial system would have to satisfy in order to take advantage of an in situ carbon source. The current state of knowledge fails to provide satisfactory evidence that existing systems can meet the constraints identified in this study; thus an ambitious program of research and development would be required to determine MEOR feasibility.
Use of Highly Acid-Soluble Chelating Agents in Well Stimulation Services
Authors: Frenier Wayne W. , Wilson David , Crump Druce , Jones Ladell
Published: December 2007

Chelating agents are materials that are used to control undesirable reactions of metal ions. In oilfield chemical treatments, chelating agents are frequently added to stimulation acids to prevent precipitation of solids as the acid spends on the formation being treated. These precipitates include iron hydroxide and iron sulfide. In addition, chelating agents are used as components in many scale removal/prevention formulations. Two different types of chelating agents are in use: polycarboxylic acids (including polyaminopolycarboxylic acids) and phosphonates. Chelating formulations based on ethylenediaminetetraacetic acid (EDTA) have been used extensively to control iron precipitation and to remove scale. Formulations based on nitrilotriacetic acid (NTA) and diethylenetriaminepentaacetic acids (DTPA) also are in use. Each of these materials has problems: 1) EDTA has low solubility in hydrochloric acid and is not readily biodegradable in standard laboratory tests. 2) NTA is acid soluble and biodegradable, but has a lower stability constant for iron than EDTA (or DTPA) and is considered to be an animal carcinogen. This report describes the search for the "universal" or "ideal" chelating agent for use in oilfield services. The materials evaluated include hydroxy-aminopolycarboxylic acids (HACA) such as hydroxyethylethylenediaminetriacetic acid (HEDTA) and hydroxyethyliminodiacetic acid (HEIDA) as well as other types of chelating agents.
Drilling of Multitarget Sinusoidal Wells to Manage Geological Uncertainty and Poor Reservoir Connectivity on the Njord Field, Offshore Norway
Authors: Tistel Jan Ivar , Andresen Svein , Lien Svein C.
Published: December 2007

The Njord field offshore Norway produces oil from a highly faulted and heterogeneous sandstone reservoir where both vertical and lateral communication is severely restricted. This paper describes how novel multitarget sinusoidal well designs have been successfully drilled and completed on Njord in order to increase production and reserves.
Determination of Hydrocarbon Properties by Optical Analysis During Wireline Fluid Sampling
Authors: Dusen Alexandra Van , Williams Stephen , Fadnes Finn Hallstein , Irvine-Fortescue Jamie
Published: December 2007

Recent innovations in wireline fluid sampling have allowed the expedient recovery of high quality oil samples. The use of the Optical Fluid Analyzer* (OFA), a part of the Modular Formation Dynamics Tester* (MDT), to predict sample fluid type and quality has now become an essential part of the sampling process. The ability to use the optical data from the OFA in a more quantitative manner has been under development for several years. This paper demonstrates that the analysis of the optical spectra measured downhole, can be used to give a quantitative indication of some hydrocarbon properties prior to or during sampling. Clearly, there are many potential benefits from using these optical spectra whilst sampling to assist in reservoir characterization and determination of oil type.

Optical data gathered while taking oil samples in 21 wells, drilled with water based mud, offshore Norway were correlated with the PVT properties of those samples. These samples were selected to ensure a wide range of oil types in order to establish correlations between the fluid and optical properties. Correlations have been found between the optical response and some fluid properties as determined from PVT laboratory measurements of the samples. Oil density, saturation pressure (Pb), oil compressibility (Co), formation volume factor (Bo) and gas oil ratio (GOR) gave good correlations. Weaker correlations were found with other properties. GOR as well as optical responses could become measured variables with the possible future addition of a GOR measurement sensor to the MDT. Improved correlations are demonstrated when this feature is simulated. The results of this study show that the optical data measured during wireline fluid sampling can help determine key in-situ hydrocarbon properties.
NMR Signal Pattern Classification for Estimation of Petrophysical Properties
Authors: Rodrigues Patricia , Alcocer Yuri , Matheus Justo
Published: December 2007

NMR signals measurements are being widely used to estimate reservoir petrophysical properties, which directly impact calculations of recoverable oil. NMR T2 distribution curves have plenty of information about rock properties, however most of the work done on this matter has been concentrated in studying only few parameters of that curve (logarithmic and geometric averages). This work is focused on the use of the total T2 distribution curve for better prediction of petrophysical properties. This means using all information of the NMR T2 distribution spectra instead of an average of them. The approach consists in the use of data mining techniques for a NMR T2 curves pattern classification. The algorithm used identified several patterns, which correlated with rock "storage" properties, such as porosity, FFI, BVF and T2 cutoff, with no apparent correlation for permeability. Using only short times of the curves, it was possible to, obtain an excellent correlation with the "transport" property of the system (permeability), reducing significantly the correlation with "storage" properties. The same analysis was done using the long times of the curves, with no correlation. These findings showed that the use of the total T2 distribution curve relates to rock "storage" properties and the use of short times of the same curve relates to "transport" properties. This very important result indicates that a specific non-linear algorithm should be used to predict the different rock properties, "storage" (porosity, FFI, BVF and T2 cutoff) vs. "transport" (permeability), from NMR signals. This new approach can potentially improve reservoir characterization and estimation of oil reserves, improving reservoir characterization and exploitation management.
A Mechanistic Model Based Approach to Evaluate Oil/Water Slip at Horizontal or Highly-Deviated Wells
Authors: Ouyang Liang-Biao
Published: December 2007

Slip velocity between phases is an important factor in interpreting production logging survey, however, no much work has been done for determining the slip velocity when oil and water flow simultaneously in a horizontal or highly-deviated well.

There are several correlations and models that may be used to determine the slip velocity, nevertheless, they were developed for vertical wells and can not be applied for horizontal or highly-deviated wells due to the different mechanisms dominating the fluid flow.

An approach has been taken to develop a flow pattern-based method to evaluate the slip velocity for oil and water flow in horizontal or highly-deviated wells. More testing of the new approach will be conducted once experimental data is available.
Detection and Characterization of Fractures in Naturally Fractured Reservoirs
Authors: Verga F. M. , Carugo C. , Chelini V. , Maglione R. , Bacco G. De
Published: December 2007

Imaging log, sonic log, optical microscopy, NMR, MRI, and tomography have greatly enhanced the possibility of measuring fracture geometric characteristics. However, the fracture hydraulic width and permeability can only be evaluated from dynamic data revealing production or adsorption along the wellbore. Different analytical approaches accounting for mud rheology and their application to several field cases where mud losses were recorded with electromagnetic flowmeters are presented to evaluate the fracture hydraulic width from mud loss measurements. Observation of mud loss evolution in time also revealed whether a single fracture or an intensely fractured zone had been intercepted by the drilling bit. Results are discussed with respect to imaging log data, core analyses, and well test interpretation results. In general, a very good correspondence was found between mud loss occurrence, fracture detection from imaging log, core data, and productivity tests.
Well Testing in Ultra-High Permeability Formations
Authors: Cox D. O. , Stinson S. H. , Stellavato J. N.
Published: December 2007

Nye County, Nevada is the home of the Yucca Mountain Project, which is the proposed site for a high-level nuclear waste disposal facility. Over the last several years, Nye County has conducted an independent scientific program to evaluate the properties of the rock units around the proposed disposal site. This work has included drilling and testing several water monitor wells in clastic, valley-fill deposits. These tests indicated extraordinarily high permeability (up to 300 darcies) in some units. Well testing in reservoirs with such ultra-high permeabilities provides a unique opportunity to identify and evaluate reservoir heterogeneities. Analyses of three tests are presented.

The Nye County tests demonstrate the applicability of petroleum-industry well-test analysis methods even for ultrahigh permeability reservoirs. The tests show a large number of unusual effects (ultra-high permeability, extreme wellbore storage, linear flow, radial flow, hemispherical flow, multiple layers, multiple boundaries, wide range of compressibility, atmospheric corrections for a pumping well, etc.) in just a few tests. The test data and interpretations are publicly available and constitute an important database for well test analysis education and training.
Petrophysical Inversion of Resistivity Logging Data
Authors: Zhang Zhiyi , Chunduru Raghu , Frost Elton , Mezzatesta Alberto
Published: December 2007

Inversion is a powerful tool for interpreting resistivity-logging data in complex situations, such as deep invasion, high conductive shoulders, thin beds, anisotropic formations, and highly deviated and horizontal wells. Inversion also provides a general means to interpret data from earlier, unfocused resistivity tools as well as the new generation of array-type instruments, allowing for accurate delineation of the resistivity structure. Although, in most cases, inversion produces solutions that are consistent with petrophysics and geology, there are occasions where consistency is not achieved. In order to address these inconsistencies, we have developed a petrophysical inversion algorithm that involves gamma ray, neutron, density, acoustic, and resistivity data in a single, unified interpretation process.

The steps in the interpretation process consist of estimating bed boundary positions from all available measurements, including gamma ray, neutron, density, and resistivity data, using a weighted inflection point method. Bed boundary positions are then adjusted using the tool response functions associated with the various instruments involved and integrated to produce a consistent set of bed boundaries, which best represents the subsurface geology and lithology. Next, upper and lower bounds for formation resistivity and flushed zone resistivity are estimated using an appropriate water saturation equation. Input for resistivity bound estimation includes shale volume, porosity, as well as the possible range of variation for water saturation, formation water resistivity, and shale resistivity. The resistivity bounds are incorporated into the inversion algorithm via an outside penalty function added to the original objective function of the optimization. The proposed inversion algorithm utilizes a generic objective function including a reference model and data weighting based on uncertainties. Furthermore, a first-order spatial-finite difference operator has been built into the objective function to eliminate unrealistic oscillations in the inversion results. A field case example shows that the proposed inversion process can effectively handle systematic noise in the data caused by borehole washouts and inappropriate bed boundary positioning, and generates petrophysically meaningful inversion results.
Reservoir Characterization for Naturally Fractured Reservoirs
Authors: Baker Richard O. , Kuppe Frank
Published: December 2007

Reservoir characterization and simulation modeling of naturally fractured reservoirs (NFRs) presents unique challenges that differentiate it from conventional, single porosity continuum reservoirs. Not only do the intrinsic characteristics of the fractures, as well as the matrix, have to be characterized, but the interaction between matrix and fractures must also be modeled accurately.

Three field case studies have been evaluated combining the "forward" modeling approach, typically used by geo-scientists, with "inverse" techniques, usually incorporated by reservoir engineers. The forward approach examines various causes of natural fractures and its' associated properties (e.g. fracture spacing, height, stress distribution, etc.) while the inverse approach focuses more on the effect created by the NFR (e.g. decline analysis, material balance, productivity, etc.).

This study shows how a more powerful methodology is created, for the evaluation of naturally fractured reservoirs, when combining two techniques that have, historically, been applied in relative isolation.

Introduction

The development of reservoir modeling and reservoir characterization for Naturally Fractured Reservoirs (NFRs) has lagged behind simpler matrix flow dominated rock systems due to the practical difficulty in quantifying both matrix and fracture parameters. The complexities of, numerical and mathematical calculations have historically constrained the development of NFR modeling1. This paper shows a number of integrated field studies, which have addressed the difficulties in characterizing NFRs, and presents a proven methodology to characterize and model them.

Reservoir characterization presents a unique challenge in NFRs because of:the need to characterize the fractures as well as the matrixthe need to characterize the matrix-fracture interaction.

Characterization of the fracture includes defining parameters such as inter-fracture spacing, length, orientation, porosity, connectivity, aperture and permeability. As well, it is important to include realistic areal and vertical heterogeneity in both the matrix and the fracture systems.

A fractured medium represents a highly heterogeneous system. Fluid transport and pressure dynamics cannot be fully replicated in a model using a homogeneous three-dimensional system.

Recent work has emphasized the need to better characterize heterogeneities in matrix properties. The same attention, if not more, needs to be given to the characterization of fracture heterogeneities. Reservoir characterization is highly dependent upon the integration of skills from geologists, geophysicists, petrophysicists and reservoir engineers to an even greater extent in NFRs than in conventional reservoirs.

The methodology presented ensures compatibility between the geological and engineering models. Specifically, this paper will show how NFR parameters were determined for the three fields in which this methodology has been applied.
Flood Evaluation by Log Analysis for Improved Recovery in Producing Wells
Authors: Smith Roger L. , Menzel R.M.
Published: December 2007

Until recently, the only parameter that usually could be accurately determined from log analyses of wells that had been flooded for secondary recovery was porosity. Now, using new techniques, it is often possible to determine whether the primary fluid produced from a zone will be connate water, flood water, oil, or gas. Actual gas saturations can be calculated, and, in open hole, wireline formation-pressure tests can be made.

This paper will discuss several log-interpretation techniques which can be used to help define the zone-by-zone production of a producing well in a field being flooded. Their further implementation by wireline-formation-pressure tests in open hole will also be mentioned. All of these techniques have been used successfully in the Permian Basin. Their uses and limitations will be briefly outlined.

Introduction

A major problem in log evaluation of fields being flooded has been that, due to the encroachment of flood water, the waters in different zones frequently have different salinities. It has been impossible, therefore, to compute water saturations accurately with just a resistivity log or just a pulsed-neutron-capture (PNC) log, since such pulsed-neutron-capture (PNC) log, since such calculations require that the analyst know the water salinity in each zone. However, using the two tools together it is usually possible to differentiate oil-producing zones from flood-water-producing zones. Thus, flood-breakthrough zones may be identified and squeezed or plugged off.

In addition to producing unwanted flood water, the operator often finds that a secondary gas cap has developed in his reservoir, causing gas production to increase drastically. Using cased-hole logs, the gas-oil contact can be defined. Gas saturation can be determined through the use of PNC and porosity logs for either open-hole or cased-hole completions. Under some conditions, oil and water saturations may also be determined.

In the Permian Basin oil wells have commonly been completed open hole. In these wells, a Repeat Formation Tester (RFT*) can be used to take as many formation-pressure tests as desired on one trip in the hole.
A Family of Viscous Gelled Water Systems Featuring Moderate Polymer Loadings and Low Residue on Breaking
Authors: Hannah Robert R. , Matson Bill G.
Published: December 2007

It has been realized for a number of years that guar gum, the most commonly used polymer for thickening water-based fracturing fluids, has a significant amount of insoluble residue. This material has retained its popularity over the years because it has a high popularity over the years because it has a high viscosity yield per dollar spent compared to other suitable polymers. Repeated laboratory testing on productive cores has also proven that damage to matrix permeability is negligible and confined to the immediate fracture wall.

Attention has recently been focused on the potential damage that can be done to the sand potential damage that can be done to the sand pack or proppant pack by heavy residue guar pack or proppant pack by heavy residue guar gels and the subsequent reduction of fracture conductivity.

Extensive research has been done to develop fluids which retain the yield of high concentration quar gum gels while at the same time reduce the damage done by insoluble residue. Simple gels formed by high concentration synthetic polymers (H.E.C., C.M.C., etc.), while free of residue, are prohibitively expensive.

This paper will discuss a family of gels designed to meet or exceed the viscous yield furnished by guar gum gels that are low or free of residue and can be pumped at a price competitive with the high concentration guar gum gels.

In each case a base gel with a low to moderate polymer loading is crosslinked after sand addition with a consequent increase in viscosity.

Clean fracturing systems will be discussed with emphasis on fluid loss, rheology, and applications. A broad range of case histories will be presented to illustrate the application of these systems in the field under a variety of conditions. Criteria for the selection of individual gel systems to match particular well conditions will be presented.

The use of these moderate polymer concentration crosslinked systems is rapidly displacing the traditional gelled water fracturing systems. Their popularity is due not only to cleaner polymers but to their ability to furnish high viscosity systems without undue polymer loadings. The use of these and polymer loadings. The use of these and similar systems is desirable in all applications where the need for fracture conductivity dictates that damage be reduced to an absolute minimum.
Numerical Simulation Study on Weak Gel Injection
Authors: Yuan Shiyi , Han Dong , Wang Qiang , Yang Hua
Published: December 2007

The low concentration flowing gel (LCFG) fluid diversion technique is a promising IOR method developed in recent years. The displacement mechanism of the weak gel, the physico-chemical properties and other influencing factors, specifically the gel formation, the physical characteristics, the mobility in porous media and the adjustment of permeability, etc., were studied in detail in this paper. A numerical simulator was accordingly established and used initially to simulate laboratory LDFG displacements with satisfactory results observed. A pilot test of the weak gel fluid diversion was consequently simulated and designed using the simulator. The scenario was optimized and economic evaluation was carried out. The pilot test has been put into implement and the performance was in agreement with the prediction.
A Petroleum Engineering Educational Model Based on the Maureen Field UKCS
Authors: Gringarten Alain C. , Bond Deryck J. , Jackson Matthew D. , Jing Xu -Dong , Ala Mike , Johnson Howard D.
Published: December 2007

Important objectives of the MSc courses in Petroleum Engineering and Petroleum Geoscience at Imperial College are educating students in the work flow concepts now prevailing in the oil industry, and producing petroleum professionals who are specialists in their respective fields but are trained to work effectively in multi-disciplinary teams. One of the tools used to meet these objectives is a group project using data from the UKCS Maureen field and made available by Phillips Petroleum (UK) Ltd. This paper describes the rationale for developing a group project exercise based on real field data, the approach used to develop the group projects and the lessons learned.