bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimation of Leakoff Pressure Gradient from Cementing and Casing Data
Authors: Zhou D. , Wojtanowicz A. K. 
Published: December 2007

Abstract
The paper describes the development and use of a new procedure for finding safe value of casing shoe leak-off pressure in surface holes in the shallow-marine sediments (SMS). Presented is a theoretical proof, supported by field data from leak-off tests, that, in SMS, annulus channeling outside cement occurs more likely at pressure values smaller than the rock fracturing pressure. Hence, for upper well sections in SMS the prediction of casing shoe strength should be based on critical conditions for annulus channeling rather than rock fracturing.
It is also shown that pressure required for casing shoe leak-off behind cement can be determined from contact stress between cement and wellbore. Contact stress develops during the process of cement setting as a result of volumetric changes in the annulus. Set up is a mathematical model of contact stress around casing shoe based on cement volume reduction and compensation from casing string, cement compressibility and wellbore. Using readily available data of well geometry, casing properties and cementing operation, simple procedure, explained in this paper, gives a good estimation of cement fracture compared with actual leak-off test values.
The study identifies two factors, related directly to drilling technology, that control critical pressure of cement channeling in SMS: contact stress at casing shoe – resulting from cementing operations, and rock penetration by liquid – an invasion of drilling fluid into the rock around the casing shoe. It is shown in the paper that changes in cementing and drilling practices may increases casing shoe integrity and reduce the need for cement squeeze treatments.
Processing of Multi-Acquisition NMR Data
Authors: Slijkerman W. F. J. , Looyestijn W. J. , Hofstra P. , Hofman J. P. 
Published: December 2007

Abstract
Crucial issues in formation evaluation are the determination of porosity, permeability, hydrocarbon volumes and net-to-gross ratio. NMR logging provides measurements that are directly related to these parameters. The NMR response of fluids contained in pores is governed by their T2 and T1-relaxation times, diffusion coefficient and whether or not they wet the rock. In the case where fluids possess a sufficiently large contrast in these properties and NMR data has been acquired with suitably chosen acquisition parameters (i.e. wait times and/or interecho times) a separation of water, oil and gas NMR responses can be made. From these separate NMR responses the hydrocarbon volumes, porosity and permeability estimates are subsequently calculated. Key in these applications is the ability to include all the acquired log NMR data into the processing towards the desired end result.
Methods exists to derive hydrocarbon volumes from T2-distribution or from echo decay data. However, these are all methods in which the difference between just two acquisitions that only differ in either wait time or interecho time are considered. Over the past years we have developed, tested and employed an alternative processing technique named MacNMR (Multi-acquisition NMR). MacNMR takes any number of log acquisitions (wait time and/or interecho time variations) and simultaneously inverts them using an rigorous forward model to the desired water and hydrocarbon T2 spectra. In this paper we discuss the concepts of MacNMR and demonstrate its versatility in NMR log processing. An example will illustrate its benefits. MacNMR is implemented across Shell operating units worldwide and has been in use for over two years now.
Enhanced NMR Logging Methods for Accurately Measuring Volumes of Gas and Light Oil in Hydrocarbon Reservoirs
Authors: Hou B. L. , Coates G. R. , Galford J. E. , Miller D. L. , Reddy A. P. , Bouton J. C. 
Published: December 2007

Abstract
Using nuclear magnetic resonance (NMR) logging to determine reservoir porosity occupied by gas or light oil currently requires data simultaneously acquired from at least two Carr-Purcell-Meiboom-Gill (CPMG) sequences having different wait-times. This dual-wait-time and dual-frequency method has been successfully applied to determine gas volumes in both clean and shaley sand formations. The success of the method relies on two factors. First, adequate signal-to-noise levels in an echo train difference must be maintained so that the gas-filled porosity and its transverse relaxation time (T2) can be accurately characterized. Second, methods must be available to reliably estimate the longitudinal relaxation time (T1) of the hydrocarbon phase needed to apply a necessary amplitude correction to the apparent hydrocarbon-filled porosity.
A new triple-wait-time and multifrequency method has been developed for determining gas and light-oil-filled porosity over a broader range of reservoir conditions. When compared with the dual-wait-time, dual-frequency logging technique, the new method offers two advantages. First, it improves the signal-to-noise ratio of the echo train difference. Second, it significantly improves the determination of T1 values for the hydrocarbons, especially when the reservoir contains oil, gas, and water. The new method thus enables a more accurate determination of the pore volumes occupied by each hydrocarbon phase as well as the pore volume occupied by water.
Results from laboratory experiments, performed on bulk fluids and a sandstone core, are presented to demonstrate the new method. In addition, a set of charts is provided as an aid in the selection of optimum acquisition parameters for logging applications.
Control of Hydrogen Sulfide in Oil and Gas Wells With Nitrite Injection
Authors: Sturman P. J. , Goeres D. M. , Winters M. A. 
Published: December 2007

Abstract
The downhole injection of nitrite-containing solutions into sour oil and gas wells under controlled conditions has been observed to effectively remove hydrogen sulfide (H2S) from aqueous and gas phases. Souring control using nitrite has been successfully applied to a gas well in the San Juan Basin of New Mexico and to an oil well in the Amoco Netherlands Rijnfield. H2S removal from topsides water separations equipment was also facilitated using nitrite. Injected nitrite ((NO2−)) scavenges H2S and prevents the activity of sulfate-reducing bacteria while it is present. H2S production from oil or gas wells treated with nitrite may be suppressed for much longer periods of time. In a 36-hour downhole squeeze in a gas well, injected NO2− removed H2S from produced gas for a period of 7 months. SRB populations in produced fluids were reduced for a period of 3 months following treatment. In an oil dehydrator, the addition of NO2− during regular operation resulted in a decrease in aqueous-phase H2S from 40-60 mg/l to less than 1 mg/l. Corrosion rate data indicated a less corrosive environment during the NO2− addition period than prior to the addition. In a downhole squeeze in an oil production well, injected NO2− decreased H2S in associated gas from 140 ppm to less than 1 ppm for 60 days following treatment. H2S levels remained below pre-injection levels for 6 months following treatment. Oil production increased immediately following the treatment, probably due to the dissolution of precipitated iron sulfides in the zone surrounding the well bore. This treatment has proven an effective means of controlling H2S in oil and gas wells as well as a method of removing iron sulfide scale from the near wellbore.
Dipping-Effect Correction for the High-Definition Induction Logging Tool Using New Geometrical Factors
Authors: Fang Sheng , Wang Tsili , Geldmacher Ingo M. 
Published: December 2007

Abstract
A new algorithm for dipping-effect correction of the High-Definition Induction Logging (HDIL) data has been developed. The new algorithm is implemented based on the newly derived geometrical factors that generalize the Doll geometrical factor to the dipping beds. Processing of the synthetic data and real logging data verifies that this new algorithm works reasonably well for a wide range of dip angles (up to 75 degrees).
A Deterministic Method for Gas Reservoir Evaluation Using Dual Wait-Time NMR and Density Log Data
Authors: Them Holger F. , Chen Songhua 
Published: December 2007

Abstract
Accurate estimates of porosity and fluid saturations are critical for the proper evaluation of a gas reservoir. These properties are determined by combining data from a dual wait-time (DTW) nuclear magnetic resonance (NMR) log and a density log. The novel deterministic method additionally yields several in-situ gas properties.
The density and dual wait-time (DDTW) technique is applicable to reservoirs where the pore-filling fluid consists of one liquid phase and one gas phase. The low proton density of the gas phase causes a reduction in the NMR signal strength resulting in underestimation of the apparent porosity. The amount of polarization for different wait-times depends on the specific spin-lattice relaxation time of each fluid and may cause additional NMR porosity underestimation. The density log, however, delivers a porosity that is overestimated because of the presence of a gas phase. Published correlations for gas properties are used to establish the new deterministic method. DDTW primarily yields the total porosity ϕ, and the flushed zone gas saturation, Sg,xo. Other derived properties are the in-situ gas density, ρg, as well as the two NMR-related properties hydrogen index, HIg, and spin-lattice relaxation time, T1g. Two field examples illustrate the method and an error propagation study supports its stability.
Improved Oil-in-Place Determination in Very Shaly Sandstones in the San Jorge Basin Using Total-Porosity NMR Logs
Authors: Khatchikian Alberto , Solanet Fernando , Ollier Carlos , Gamin Héctor 
Published: December 2007

Abstract
NMR logs run in oil-bearing, shallow sandstones in the Las Heras area of the San Jorge basin indicate that many reservoirs are shalier and have a much lower effective porosity than generally assumed from cores or conventional log evaluation based on density logs. This would imply that oil-in-place determination based on cores or density logs is overestimated, leading to erroneous estimates of recovery factors.
Extensive coring in a well with very shaly sands proved that NMR porosity for T2 above 3 ms is effective porosity, as clay content from infrared spectroscopy (FT-IR) measurements matched shaliness derived from NMR's total and effective porosity. As expected, core porosity (which includes clay-bound water) closely matched NMR total porosity.
Comparison of Permeability from NMR and Production Analysis in Carbonate Reservoirs
Authors: Quintero L. , Boyd A. , Gyllensten A. , El-Wazeer F. 
Published: December 2007

Abstract
Several issues come to mind in the pursuit of log-derived permeability. Two of them, often referred to in recent publications, are the accuracy of the parameter and the representative of this permeability. Permeability from nuclear magnetic resonance (NMR) logs is often compared to core, wireline formation tester mobility, drillstem test and production data. The variation in vertical and lateral extent of these different measurements can give valuable insight into reservoir behavior. Average matrix permeability can be estimated from wireline NMR measurements while the other methods can more accurately evaluate the directional reservoir permeability as it varies with heterogeneities such as vugs, fractures, maximum horizontal stress and stylolites.
Determining matrix permeability in carbonates from NMR data has been considered more difficult than in typical sandstone reservoirs. Recent developments in NMR carbonate analysis have provided insight as to how the permeability estimation from NMR logs can be improved. A method will be presented that overcomes some of the limitations of using NMR permeability in carbonates and will be compared with conventional NMR permeability estimation, core, wireline formation tester and drillstem test analysis in three Middle East carbonate reservoirs.
Oriented Drilled Sidewall Cores for Natural Fracture Evaluation
Authors: Laubach S. E. , Doherty E. 
Published: December 2007

Abstract
A procedure to orient drilled sidewall cores and to evaluate large natural fractures using microfracture indicators was successfully tested in three gas wells in Silurian Medina Group, Appalachian basin. Microfractures from these cores document the strike of fractures that control production. By running well bore image logs after coring, sidewall core holes can be detected and core azimuth determined. The main challenge to orienting the 1-inch-diameter cores is determining "up" direction, because sedimentary facing indicators are rarely visible, and currently deployed sidewall coring devices do not mark (scribe) cores. To find core tops we used fracture surface marks induced on core ends during recovery and examined image logs. Success rate for this core-orientation procedure is remarkably high, in these examples close to 85 percent. This shows that cost-effective sidewall core orientation is feasible. Oriented core, along with useful indicator microfractures, is a practical source of information on the attributes of large fractures.
Integration of Core and Log Information To Improve the Representation of Small/Medium-Scale Heterogeneity
Authors: Coll C. , Jing X. D. , Muggeridge A. H. 
Published: December 2007

Abstract
Reservoir heterogeneities exist at several length scales. Reservoir properties will depend on the scale that we are analysing on the reservoir (from core to grid block). Facies are normally identified in cores and classified based on microscopic and small scale features such as lithology, grain size, texture, sedimentary structure, colour and fossil content. However, facies information is only available in a few cored wells or in wells with high vertical resolution logging. Conventional logging is usually available in all wells, but it only provides information at a medium scale. This information can be calibrated with geological facies to generate electrofacies (also called petrofacies),1 from which reservoir property distributions can be predicted using 3-D modelling techniques.
In this paper, core and log information is integrated to create a facies and electrofacies database. Small-scale geological facies are calibrated with logs and used to generate electrofacies by using statistical analysis. More detailed geological models are then generated using electrofacies data. The impact of using an electrofacies scehme over the traditional log-derived facies scheme during stochastic modelling of reservoir facies has been demonstrated. Modelling performance prediction using both methods is analysed for the different stochastic realisations. The use of electrofacies schemes has been proved to give more accurate prediction of reservoir heterogeneity.
Application Limits of Stainless Steels in the Petroleum Industry
Authors: Oberndorfer M. , Kaestenbauer M. , Thayer K. 
Published: December 2007

Abstract
Stainless steels have a great variety of potential applications in the petroleum industry, mainly as an alternative to carbon steel in corrosive environments. Within a number of media that can cause corrosion problems with these materials, only chloride solutions and hydrogen sulfide are of importance in oilfield service.
A reliable tool that permits the proper selection of stainless steels has yet been missing. In order to provide engineering diagrams for this purpose, pitting and stress corrosion cracking (SCC) tests were performed. Specimens were exposed to NaCl solutions containing from 3 to 100,000 ppm Cl− at temperatures from 40 to 200 °C. This test configuration was chosen to give a better representation of actual service conditions than accelerated standard test procedures do.
Tested materials were the austenitic stainless steel grades 321, 316Ti (API LC30-1812) and 254 SMO, and 22Cr duplex (austenitic-ferritic) steel (API LC65-2205). Based on an optical examination of the specimens, no-risk regions of chloride concentration vs. temperature have been identified. Subsequently, service temperature limits have been deduced for each tested material.
Thus, material failures by pitting and SCC can be prevented without overdesigning. The results of the testing series are applicable to all chloride environments without presence of H2S, as they have to be handled by primary production equipment, as well as transportation and gas processing facilities.
Stress-Dependent Permeability: Characterization and Modeling
Authors: Davies J. P. , Davies D. K. 
Published: December 2007

Abstract
During the production lifecycle of a reservoir, absolute permeability at any given location may change in response to an increase in the net effective stress and a concomitant decrease in the value of in-situ permeability. This paper focuses stress dependent permeability in unconsolidated, high porosity sand reservoirs (offshore turbidites) and consolidated reservoirs (tight gas sands). Specifically we address: i) fundamental controls on stress dependent permeability, as identified through analysis of core samples, ii) rock-based log modeling of stress dependent permeability in cored and non-cored wells, and iii) implications for production based on data from reservoir simulation. This work reveals a fundamental difference between the stress dependent permeability behavior of unconsolidated and consolidated sand reservoirs. In unconsolidated sand reservoirs, the greatest permeability reduction with stress occurs in the sands with the highest values of porosity and permeability. In cemented sandstone reservoirs, the opposite is the case: most of the reduction in permeability occurs in sandstones with the lowest values of porosity and permeability. This difference in behavior between unconsolidated and consolidated reservoir sands is controlled by pore geometry.
We present a practical, rapid and cost efficient methodology to improve evaluation and enhance the productivity and management of stress-dependent reservoirs. The method is based fundamentally on the identification of ΑRock Types≅ (intervals of rock with unique pore geometry). Thin section evaluation, together with integrated nuclear magnetic resonance and SEM-based image analysis of core material is used to quantitatively identify various Rock Types. Rock Type data is integrated with measurements of permeability at various levels of stress. Results demonstrate that, within a particular field, some Rock Types lose &lt;10% of original permeability while others lose &gt;90% of original permeability as a function of increasing stress. Rock Types are then identified using routine suites of wireline logs, allowing for field-wide determination of the net footage and distribution of each Rock Type in all wells and the foot-by-foot calculation of permeability at any value of net effective stress. Based on geological input, the reservoirs are divided into flow units (hydrodynamically continuous layers) and grid blocks for simulation.
Several cases are presented of a conceptual, single well model of an overpressured, tight gas sandstone reservoir that include stress dependent permeability. Results of simulation analyses for varying conditions of reservoir stress demonstrate the importance of stress dependent permeability in more accurate forecasting of reserves and predicting optimum well bore producing conditions.
Quantification of the Contribution of the Different Components Concerning Two-Phase Flow in Heterogeneous Porous Media
Authors: Berentsen C. W. J. , van Kruijsdijk C. P. J. W. 
Published: December 2007

Abstract
Two phase flow through heterogeneous porous media can be divided in ‘convective’ and ‘diffusive’ flow processes. The ‘convective’ part consists of the flow behaviour due to the large scale permeability field variations and an additional ‘two phase’ part generally captured in relative permeabilities. The ‘diffusive’ process is generally captured in the capillary pressure formulation. In this study we express the two phase flow behaviour as a convolution between the multidimensional single phase (tracer) flow behaviour with the one-dimensional two phase flow behaviour. For Piston like flow through a more dimensional heterogeneous medium, the velocity field remains constant during flooding and one can divide the flow field in constant ‘one-dimensional’ streamtubes, see Lenormand (1995). Under the assumption that the variation in streamtubes through the same field during two-phase flooding is negligible one can express the watercut profile of two phase flow in the watercut profile for Piston like flow convolved with the Buckley Leverett saturation profile.
In this study we compute the Piston like flow through three different permeability fields (one homogeneous field and two heterogeneous fields with an omni-directional correlation length of 0.5 respectively 0.95). We calculate 4 different two-phase flow behaviours by means of convolution and compare this to fully two dimensional flow simulations performed with an in house developed streamline simulator. We define a measure - based on the difference between Piston like and Buckley Leverett production - to quantify and characterise each different two-phase flow type. It appears that the convolved two phase flow behaviour shows a reasonable estimate of the fully two-phase flow behaviour, although the difference in the two dimensional total mobility distribution can affect the moment of breakthrough considerably. The defined production measure appears to show similar results for both the convolved and fully simulated two phase displacements. The benefit of the convolution method is that with only a single high resolution Piston like displacement numerous different two phase flow displacements can be estimated very cheaply.
Reservoir Heterogeneity Mapping Using an Automated Pattern Recognition Approach
Authors: Hassibi Mahnaz , Ershaghi Iraj 
Published: December 2007

Abstract
In reservoirs with complex structure, such as turbidite sequences, rock fabrics exhibit great variations both vertically (example-Bouma sequences) and in lateral direction. In such formations, patterns observed on lithological logs can show considerable differences. Constructing rational and meaningful correlation models consistent with all the lithological signatures can be an enormous task before conceptualization of data on a 3-D geologic model. The proposed method can serve as an important pre-processing step to minimize the requirements of the human expert input in the sub-marker detection for substantial number of well logs. The automated techniques of pattern classification enhance the characterization and identification of stratigraphic features of laminated type reservoirs. The approach proposed in this paper works on basic lithological logs and marker information. It comprises noise filtering and pattern recognition that lead to identification of reservoir compartments. This helps in delineation of the lateral continuity and discontinuity of reservoir sand and shale laminations.