bluuebunny/crossref_metadata_2025_split huggingface dataset:
Scale Inhibitor Selection for Continuous and Downhole Squeeze Application in HP/HT Conditions
Authors: Graham G.M. , Dyer S.J. , Sorbie K.S. , Sablerolle W.R. , Shone P. , Frigo D. 
Published: December 2007

Abstract
With the development of a number of new HT/HP fields in the North Sea, for example the ETAP fields (Eastern Trough Area Project), a number of important "scale" control issues have arisen. In addition to harsh downhole conditions (T - 180 C; P - 13,000 psi), high salinity formation water chemistries indicate that the control of inorganic precipitates in these systems will be very important. The form of the inorganic precipitates are predicted to include the more Cornnjton oilfield scales (BaSO4 and CaCO3). In addition the very high salinity of several of the formation brines (TDS - 350,000 ppm) can result in halite precipitation (NaCl(s)). This occurs either as a result of water flash-off into the gas phase as pressure decreases during production or simply due to reduced halite solubility as temperature and pressure decline during production.
This paper discusses the potential scaling problem associated with these harsh reservoir conditions and outlines various solutions for treating such reservoirs using conventional scale inhibitor technology. A series of different generic scale inhibitor chemistries have been assessed for their potential application in such reservoirs. The assessment has involved a range of laboratory procedures including thermal stability, brine compatibility, carbonate and sulphate inhibition efficiency testing. These tests were conducted at temperatures up to 180C. The laboratory screening procedures led to the selection of the most appropriate generic chemical types which are applicable for scale inhibitor treatment under HP/HT reservoir conditions. Further studies then examined the most appropriate species for application downhole as squeeze treatment chemicals under HP/HT conditions. This included static adsorption tests conducted at temperatures and pressures ranging from 950C at saturated vapour pressure (SVP) to 180C and 7,500 psi. Reservoir conditioned core flooding studies were conducted on the two most appropriate species in order to assess formation damage issues and to derive their respective adsorption isotherms in order to model potential squeeze lifetimes.
P. 645
Waxy Crude Cold Start: Assessment Through Gel Structural Properties
Authors: Cazaux G. , Barre L. , Brucy F. 
Published: December 2007

Abstract
During prolonged shut-down of pipeline transporting waxy crude oils and cooling, crystals of paraffins are formed within the fluid bulk and can interlock into a continuous gel-like network. Then, a restarting pressure is required to break the gel and resume flow, the resistance of gel to flow naturally resulting from its structure state. This paper addresses the understanding of the mechanisms of cold start-up of flow, through the assessment of the structural properties of the gelled oil.
A set of laboratory techniques has been used to investigate the building-up of the gel structure after a cooling at rest. Two stock tank crude oils were tested for this investigation. As a result, the experimental data are combined into a description model of the development of the gel network as temperature decreases. Physical significance of Wax Appearance Temperatures is discussed from this model.
It is concluded that the relevant parameters to build a structural model and understand the flow properties of these gelly oils are size, shapes (ratio axes) and number of paraffin crystals, and that they depend on temperature and cooling history.
P. 729
Evaluation of Long-Term Effluent Water Disposal Options in the Greater Burgan Field
Authors: Brown D.R. , Jones P.S. , Al-Saif K. 
Published: December 2007

Abstract
Effluent, which is a mixture of produced and brackish water from the Greater Burgan Field operations, has historically been disposed of through the use of evaporation pits. While this has worked adequately in the past, some of the Gathering Centers (GC) are unable to handle the ever increasing volumes with evaporation pits. Between environmental concerns, the decreasing capacity of the pits and the increasing volume of water, alternative disposal methods needed to be considered. Kuwait Oil Company (KOC) embarked on a study to look at the various options of disposing of its increasing volume of effluent water. A multidisciplinary team composed of Reservoir Engineers, Geologists, Operations personnel and Facility Engineers was assembled with the task of developing recommendations. Their efforts encompassed a review of alternative disposal options, reservoir assessment, on-site coreflood tests, two pilot disposal projects, and a survey of water quality.
P. 555
A Method for Determining Average Reservoir Pressure and Inflow Performance from Historical Surface Flowing Data in the Gomez (Ellenburger) Field, Pecos County, Texas
Authors: Adams L.S. , Norris H.L. , Schumacher B.W. 
Published: December 2007

Abstract
This paper presents the development and application of a method for determining average reservoir pressure and inflow performance parameters from historical surface flowing data for deep, high-temperature, gas wells located in the Gomez (Ellenburger) Field, Pecos County, Texas. This method provided suitable average reservoir pressure, improved p/z versus Gp data, and inflow performance optimization where a significant lack of reservoir data existed. The versatility, risk reduction, and cost-effectiveness of this methodology are also discussed.
P. 577
A Generalized Material Balance Equation for Coal Seam Gas Reservoirs
Authors: Penuela G. , Ordonez A. , Bejarano A. 
Published: December 2007

Abstract
During the last few years, research has been done on generalized material balance equations for conventional oil and gas reservoirs in order to improve the reservoir performance analysis. However, those equations are inappropriate for coal seam gas (CSG) reservoirs. To address this limitation, a generalized material balance equation (GMBE) for CSG reservoirs was developed. This work is based on a mathematical development and the straight-line method, published previously and widespread used for conventional reservoirs.
Three validation examples of the proposed equation were designed. They show the new equation has the following advantages:it is applicable to CSG reservoirs in saturated, equilibrium, and undersaturated conditions,it is applicable to any type of coalbed without restriction on especial diffusion constant values,existent equations are particular cases of the generalized equation evaluated under certain restrictions, andits reorganization is analogous to the popular straight- line method for conventional reservoirs.
P. 621
A Study on Two Phase, Non-Darcy Gas Flow Through Proppant Packs
Authors: Jin L. , Penny G.S. 
Published: December 2007

Abstract
The effect of liquid phase on non-Darcy gas flow through proppant packs has been characterized by correcting the non-Darcy flow Forchheimer coefficient as a function of liquid saturation in the proppant pack in the past. Through an extensive experimental study it is found that at high liquid saturation, Forchheimer correlation does not hold anymore. A non-linear relationship appears that cannot be characterized by factor alone. Tests are focused on the investigation of the effect of proppant properties (permeability and porosity), liquid properties (density and viscosity), and gas properties (density and viscosity) on the non-Darcy, two phase flow behavior. An empirical model that uses the liquid to gas ratio to predict the effective permeability or conductivity of a proppant pack under two phase, non-Darcy flow conditions is discussed in the paper.
Based on the fact that proppant packs have relatively narrow pore size distributions, a simplified physical model has been developed to represent two phase (liquid and gas), non-Darcy flow through proppant packs. The purpose of developing the model is to understand the effect of gas flow on the velocity of liquid in a two-phase flow process. As a result, the model can calculate a mobile liquid saturation corresponding to each combination of gas-liquid flow rate. The relative permeability of a proppant pack at different conditions can then be calculated taking both non-Darcy and two phase flow effect into account.
P. 675
Development of Drilling Facilities for a Field Development in the Caspian Sea
Authors: Nichols J. , Scoular T. , Hagger P. 
Published: December 2007

Abstract
The Caspian region is currently the focus for the rehabilitation of existing fields and the development of new offshore fields. This is providing unique opportunities for both operators and contractors. New drilling facilities are currently being designed for these fields by an integrated operator and drilling contractor team. Ensuring that the lessons learned from previous projects, both from within the Caspian and other areas, is essential, so that the optimum technical and economic solution is selected. At the same time the limited transportation options into the region and current local infrastructure constraints add an extra dimension to be overcome.
This paper will discuss how the design for a platform drilling rig, complemented by a lightweight completion rig has evolved in preference to installing two full size drilling rigs on a single drilling jacket. This combination is planned to be deployed on two drilling platforms in the Caspian Sea during 2001. The involvement of operations personnel in the project from the outset has allowed many of the previous failings of simultaneous operations elsewhere to be eliminated during the design.
The arrangement will provide a significant Capital expenditure saving as well as reduced operating costs. The ramp up to peak production will only be marginally slower than if two full size twin rigs were installed. It is expected that the design will form the basic building block for the remainder of the field development.
P. 741
Slimhole Drilling and Coring - A New Approach
Authors: Bencic A. , Prohaska M. , de Sousa J.T.V. , Millheim K.K. 
Published: December 2007

Abstract
Over the past years, slimhole drilling has proved to be a cost effective way of drilling certain exploration and exploitation wells. However, one of the major downsides to slimhole drilling are poor penetration rates as compared to conventional hole sizes.
The paper presents the design and proof of a dual-body bit concept which gives the user the possibility to change the bit's characteristics (profile, cutting structure, hydraulics, etc.) and thus alter its performance significantly without the necessity of a round trip.
Additionally, with this approach, the purpose of the drilling mode can be easily switched from coring to full hole drilling and vice versa. This is done, similar to the process of adjusting the bit, from the surface with the use of a conventional wireline assembly, which gives a reasonable potential for improvement for the overall drilling process.
The idea for this new drilling approach emerged from a research project that initially had the aim of filling the gap of optimal slimhole PDC drill and core bit design. The studies confirmed that there is a limitation for the use of PDCs when drilling certain hard, heterogeneous multi-layered formations, no matter how sophisticated the bit design itself might be. After exhausting all conventional slimhole PDC bit designs it became evident that an entire new paradigm was needed. The mining industry had experimented with the two body bit, but had never seriously exploited the concept for sedimentary drilling. Today the possibility of easily running the inner bit and retrieving it is standard technology. This project has taken the mining technology to a higher level by introducing the concept of dynamically changing the properties of the bit downhole (without tripping) to optimize penetration rate performance for all kind of sedimentary rocks. Results from an in-house laboratory testing series are included, documenting first dual body bit design efforts, and performances achieved.
P. 771
Control of Shale Swelling Pressures Using Inhibitive Water-Base Muds
Authors: Chenevert Martin E. , Pernot Vincent 
Published: December 2007

Abstract
Over the years wellbore stability in shales has been achieved using oil base muds, however water base muds still plague the industry. Up until now it was not obvious what mechanisms were in operation during such shale/water base mud interactions. The research reported herein discusses the development of swelling pressures when water base muds are in contact with a troublesome North Sea shale. A mechanistic theory is presented that focuses on increases in total pore pressures that are reflected in swelling pressures. The results obtained showed that different mud filtrates produce swelling or shrinking pressures that are related to the type of salt present and its ionic concentration. Fluids tested included de-ionized water and solutions of CaCl2, Potassium Formate, Glycerol, Methyl Glucoside and NaCl/Methyl Glucoside. The range of swelling pressures measured were from +2800 psi (swelling) to -1400 psi (shrinkage). In addition to swelling pressures, the compressive strength of the shales was also measured under downhole insitu stress and conditions after the chemical interactions were complete. Strength reductions as high as 35% were measured for certain fluid systems.
Determination of Gas-Condensate Relative Permeabilities from Field Production Data
Authors: Sumnu-Dindoruk M.D. , Jones J.R. 
Published: December 2007

Abstract
Gas condensate reserves are increasing in size worldwide as more and more deep wells are drilled. Increased modeling efforts to optimize the performance from gas condensate reservoirs need accurate and reliable determination of condensate relative permeability curves. The use of nonrepresentative relative permeability curves may result in over/under estimates in performance predictions.
Laboratory measurement of relative permeabilities is the most common method used in relative permeability determinations. However experiments by using field representative cores and fluids at reservoir conditions are expensive and difficult to conduct. That is the reason why laboratory measured relative permeability curves are scarce and contradictory in nature.
On the other hand field automation data such as production rates and recoveries are usually available from the field. In this paper we propose a quick and reasonable method to estimate the gas and condensate relative permeabilities using this type of data. Our procedure is a modification of a method presented by Fetkovich et al. for black oil systems. Our modifications allow us to deal reasonably well with the nonuniform saturation distributions which play a unique role in the performance of gas condensate systems. The method requires flowing pressures, gas and condensate production rates and PVT properties of the condensate fluid. The new method was tested via simulation for a rich condensate fluid and it worked well in estimating the relative permeabilities. The major advantage of this approach is that the relative permeabilities calculated are representative of field performance. Hence the relative permeability curves obtained represent a naturally upscaled set of curves which can be used directly or as a guide in upscaling laboratory measurement curves.
P. 655
Uncertain Cap Rock Geometry, Spill Point, and Gross Rock Volume
Authors: Abrahamsen Petter , Hauge Ragnar , Heggland Knut , Mostad Petter 
Published: December 2007

Abstract
The geometry of the cap rock of a petroleum reservoir is never exactly known so that the depth and lateral location of the spill point are uncertain. Therefore, the gross rock volume of a filled structure is uncertain due to uncertainty in cap rock geometry and the depth to the hydrocarbon contact determined by the spill point. A method for evaluating this uncertainty has been developed. First, the geometry of the cap rock is simulated using established Monte Carlo simulation techniques for surfaces based on Gaussian random field models. Secondly, a new fast algorithm finds locations of spill points and trapping areas of the simulated structures. Finally, gross rock volume of the traps can be calculated and volume distributions can be quantified in terms of histograms and quantities. The spill point detection algorithm is fast and reliably even on complex and irregular structures.
A synthetic example and an example from the North Sea illustrate the possibilities and properties of combining a fast spill point detector with Monte Carlo simulation of surfaces.
P. 723
Simulation of Permeability Field Conditioned to Well Test Data
Authors: Srinivasan Sanjay , Journel Andre G. 
Published: December 2007

Abstract
Well testing provides critical information about the effective permeability value around the well being tested. That information must be integrated with higher resolution, smaller scale, well log data. The difference of scale is handled by kriging with "block" averages, while the non-linear averaging of permeability values is addressed by working on specific non-linear power transform of the original permeability data. A case study shows the simulated permeability fields to honor, in expected value, the well test-derived effective permeability values in addition to honoring the smaller scale well log data and statistics. Ignoring the well test information would result in permeability fields that are imprecise around the well being tested and which display too large uncertainty. The necessity of data integration, even when data are of widely different scales, is demonstrated. The paper also discusses cases when the well test-derived effective permeability appears inconsistent with the well-log derived smaller scale permeability data. The paper points out the limitation of the linear power-averaging formulation for capturing the dynamics of fluid flow.
P. 731
Improving Field Economics Through the Use of Modern Casing-Corrosion Logging Tools and Techniques
Authors: Wheeler Ralph R. 
Published: December 2007

Abstract
Because casing integrity is vital to the success of sidetrack, workover, recompletion, and enhanced-recovery operations, it is important to use reliable means of examining casing downhole. Modern casing inspection tools provide valuable diagnostic information for planning future work in a single well or an entire field.
An operator wished to improve economics in a field where casing corrosion and water production was becoming a significant problem. The goal was to increase overall production and reduce production costs by (1) performing remedial work on wells that still had production potential and could be repaired, and (2) discontinuing production from the remaining wells.
A critical component in the operator's plan was the selection of wells in which corrosion problems were not severe enough to preclude remedial operations. Complete histories were not available for every well, so the operator chose to use the latest technology and techniques in electromagnetic, acoustic, and video logging for corrosion detection and evaluation.
Electromagnetic logs were used to grade casing, create pipe tallies, and identify pipe anomalies on the inner and outer casing surfaces. Acoustic logs were used to image the interior of the pipe, analyze internal corrosion, and study cement bonding to the casing. Video logs provided real-time views of the downhole casing environment for assessing casing problems, locating fluid entry points, and identifying fluid phases.
This paper discusses the corrosion-logging program that was developed for this field. Examples are presented of different problems encountered, the solutions recommended, the results obtained from those solutions, the current status of the wells, and the economic impact of the casing evaluation program. The paper discusses the logs used in this program, and includes comparisons of different log types. Furthermore, photographs of casing pulled from one well are compared with an electromagnetic log run in that well.
P. 761
A Robust Permeability Estimator for Siliciclastics
Authors: Herron M.M. , Johnson D.L. , Schwartz L.M. 
Published: December 2007

Abstract
A permeability estimator is constructed from the lambda parameter, A, which is the size of dynamically connected pores. For simple pore geometries at high permeabilities, A should theoretically be proportional to the pore volume-to-surface area ratio. Further, at high permeabilities, the permeability is proportional to A2/F, where F is the formation factor. Core data are used to establish the proportionality constant. For permeabilities less than about 100 mD, this formula overestimates the actual permeability by a factor related to the original estimate. Thus, a corrected second estimate can be readily made, and the combined estimate is shown to match measured permeabilities on a diverse set of sands and shaly sands with a correlation coefficient of 0.89 for log k. The estimate can also be made using NMR relaxation time data, instead of the surface-to-pore volume ratio, with a correlation coefficient of 0.92 for the same data set. The estimate can also be made from mineralogy or lithology data, in which each mineral or lithologic fraction is assumed to have a fairly constant specific surface area. Examination of the data suggests that only about 10% of the total clay mineral surface area normally influences fluid flow. For Fontainebleau quartz arenites, the resulting estimate has a correlation coefficient of 0.99 with the measured permeabilities. For Utah sands and shaly sands, the mineral-based estimate has a correlation coefficient of 0.84 with the measured permeabilities; the lithology-based estimate had the same correlation coefficient. Using the lithology-based form of the equation, accurate permeability logs are derived from geochemical logs in Utah and from conventional logs in Venezuela..
P. 777