bluuebunny/crossref_metadata_2025 huggingface dataset:
Implications of Brine Mixing in the Reservoir for Scale Management in the Alba Field
Authors: Paulo J. , Mackay E. J. , Menzies N. , Poynton N.
Published: December 2007

This paper brings the discussion on brine mixing initiated at the 1999 SPE Symposium on Oilfield Scale full circle, and suggests that different scaling regimes may exist in any given reservoir that should impact the scale management strategy. The initial paper by White et al. (1999) identified lower than expected barium levels in many wells in the Alba field, and raised the question of where scale deposition is occurring. A follow-up paper at the same meeting the following year by Mackay and Sorbie (2000) identified from a theoretical standpoint where brine mixing should be expected, and suggested that significant scale deposition may occur deep within the reservoir, particularly where a large proportion of injected water sweeps through the aquifer. The current paper seeks to apply that theoretical analysis to the Alba field, on a well-by-well basis, to establish whether diagnostic tests can identify which wells should be treated conventionally, and which require special attention.

Firstly, production data and produced brine compositions are analysed to identify any recurring patterns. Wells are then classified and grouped according to various types based on this analysis. Well properties such as location within the reservoir and orientation to the flood front are then compared to identify whether they can be used to give a similar grouping of wells. Three principal zones are identified, with position relative to the injection wells and the aquifer identified as key parameters. Secondly, the flow patterns around each well are studied using the existing reservoir flow model. Modelling the dynamic mixing patterns throws further light on the differences between the zones, with scale dropout predicted in the aquifer in some areas, and in the oil-leg in others.

Recommendations are made regarding the treatment of existing wells and the optimum positioning, from a scale prevention perspective, of any new wells.
Lead Deposits in Dutch Natural Gas Systems
Authors: Hartog F. A. , Jonkers G. , Schmidt A. P. , Schuiling R. D.
Published: December 2007

During the production of natural gas from Dutch Rotliegend and Kupferschiefer sediments, next to "conventional" carbonate and sulphate scales, sometimes also lead deposits are formed. These deposits, which vary in composition from galena (lead sulphide) to elemental - metallic - lead and complex lead(hydr)oxides, may form a serious thread to operations because of their tendency to cause the blocking of production equipment or (water) injection pumps and tubing. In some cases radioactive lead (lead-210; half life 22.3 years) is incorporated into these compounds at levels above regulatory concern, which necessitates additional safety measures during operations and maintenance.

In sour gas wells, the deposition of galena can be explained by local supersaturation (caused by a sudden temperature or pressure drop) where bisulphide anions react with lead cations in the produced water, in which concentrations of up to 150 mg lead per litre brine have been detected. In the absence of hydrogen sulphide and even in "dry" gas wells, the deposition of metallic lead has been observed locally at rates of 10 grams per day or more. An electrochemical mechanism is held responsible for lead deposition on carbon steel tubing: iron from the tube wall is oxidised by lead ions in solution, leading to corrosion of the wall and the deposition of lead scales with a thickness of 10 mm or more. Under unfavourable conditions or during maintenance operations, metallic lead is easily converted into secondary lead minerals.

Detailed knowledge on the (geological) origin, the transport pathways to surface facilities and the mechanisms of lead scale formation, might enable the future development of techniques by which lead deposition can be prevented.
An Electrochemical Approach For The Protection Of Metal Surfaces From Formation Of Calcium Carbonate Using Bulk "Jar Tests"
Authors: Labille S.C. , Morizot A.P. , Neville A. , Graham G.M.
Published: December 2007

This work describes the beneficial effects of an electrochemical treatment on scale adhesion and formation. Previous studies by the present authors have shown that an electrochemical treatment can be used to promote the adsorption of polyelectrolyte inhibitors at metallic surfaces. The objective of this project is to observe the effects of the inhibitor film, deposited electrochemically, on the scale formation. "Jar tests" have been carried out. Four techniques, namely SEM, AFM, optical microscopy and scale dissolution, have been used to quantify the deposition in the presence and absence of the inhibitor film. The electrochemical treatment in presence of Mg has shown some promising results to inhibit calcium carbonate scale. The mechanisms relating to the formation of the Mg/inhibitor-containing film adsorbed during the electrochemical treatment and the potential applications of the technique will be discussed.
Laboratory Determination of Calcium Carbonate Scaling Rates for Oilfield Wellbore Environments
Authors: Zhang Yuping , Farquhar Rod
Published: December 2007

Calcium carbonate is a commonly occurring oilfield scale which proves to be difficult to manage. Carbonate scale prediction can be improved by considering the kinetic chemistry in addition to the conventional thermodynamics based predictive techniques. To improve the performance of a predictive model, a thorough understanding of the physical influences on carbonate scale kinetics is required. The work presented in this paper includes new data, experiment technique improvements and preliminary investigations into the efficiency of scale inhibitors. The new data acquired from the experiments described in the paper has been incorporated into our existing kinetic scale prediction model and a combined thermodynamic and kinetic computer model has been developed. An example is given which demonstrates how the combined model can be used to predict oilfield downhole carbonate scale profile and study the impact of production parameter changes, such as increasing water cut.
An Experimental Study to Evaluate Water Vaporisation and Formation Damage Caused by Dry Gas Flow through Porous Media
Authors: Zuluaga E. , Muñoz N. I. , Obando G. A.
Published: December 2007

Experiments were conducted to evaluate the rate of water vaporisation and the consequent permeability reduction caused by the flow of dry gas through porous media. Two sets of porous media were studied: unconsolidated Ottawa sandpacks and consolidated Berea cores, as well as various salinity brines ranging from 0 to 150 g/litre of NaCl. The experiments were conducted at an initial water saturation of about 14% for sandpacks and 24.6% for Berea cores. Tests indicate that the rate of water vaporisation increases with gas flow rate and decreases with salinity. The vaporisation of water from the porous media can result in halite drop-out. This might cause a reduction in the permeability of the porous media. The experiments showed that the reduction in permeability for sandpacks ranged from 0% for the lowest salinity to around 21% for the highest salinity used. In consolidated Berea cores this reduction ranged from 9% to 53% for the lowest and highest salinity respectively.
High Density CCL Memory Tool To Confirm SSD Sleeve Position
Authors: Daniels Jim , Williams Garry
Published: December 2007

A large number of Mœrsk Olie Og Gas AS completions in the Danish Sector of the North Sea utilise Sliding Side Doors (SSD's) as a means of zonal isolation. As the majority of the completions are in highly deviated / horizontal wells, these sleeves are manipulated by shifting tools on coiled tubing (CT). Experience has shown that the operating of SSD's on coiled tubing can lead to uncertainties in the true status of the sleeve position. Several cases have arisen where subsequent Memory Production Logging Tool (MPLT) surveys have identified SSD's that were not in their expected status.

Though MPLT's were successful in the determination of SSD status, operational and cost considerations required a new approach. What was required was a reliable, accurate means of verifying SSD sleeve position with data acquired on the same run as the sleeve manipulation tool. There were two strands to this project, the proof of concept in the ability to identify sleeve position using Memory Casing Collar Locator (MCCL) data, and the development of a "stand-alone" MCCL tool, rugged enough to be run in conjunction with the SSD manipulation tools.
A novel approach for tubing repair in a HPHT well
Authors: Rodenboog Coen , Staal B. J.
Published: December 2007

This paper describes the various steps involved to safely suspend a HPHT well and to repair a number of leaks in the production tubing. The tubing leaks were the result of corrosion and occurred over a two hundred meter interval.

Thorough analysis and associated difficulties to resolve this problem lead to the approach of cementing the tubing in place. Thus allowing the operator to test this gas well and increase the knowledge of the reservoir to develop this field. The process and solution will be described in great detail and will serve as the basis for similar problems in the future.
Development of Collapse Ratings for High Temperature and Pressure Coiled Tubing Applications
Authors: Luft H. B. , Wright R. , Lallemant F. , Kis P.
Published: December 2007

In the spring of 1998, BJ Sevices and Total Oil Marine carried out an "HP Intervention Feasibility Study" for the reliable entry of a high pressure gas well using 1 ¾" 100 ksi Coiled Tubing. The research was prompted by the requirement to use Coiled Tubing to enter Triassic wells on the Alwyn North platform in the North Sea for post frac cleanout operations among other service requirements. Potential wellhead pressures of 7,500 psi and operating depths of 6,000 metres meant that a better understanding of Coiled Tubing collapse mechanisms and an improved method of predicting collapse would be vital to optimize operations on Triassic wells. The first phase of this study was based on experimental fitness-for-purpose investigations involving a 3060 ft long test string at an on-shore test well in Aberdeen, Scotland. Recognising the conservatism of collapse resistance predicted by existing theoretical methods and appreciating that knowledge of actual collapse limits is more critical in High Temperature and High Pressure (HPHT) coiled tubing operations, this initiative culminated in a joint research venture between the operator and the coiled tubing service provider. The second phase of this research involved a laboratory collapse-testing program conducted in Edmonton, Alberta, that set out to obtain extensive experimental data on CT collapse and to investigate the effect of loading history on the residual collapse strength.

This paper is concerned primarily with the laboratory-testing program. The testing protocol is described and the key parameters that influence collapse resistance are identified and discussed, as well as how each may be affected by plastic cycling, high temperature and/or high pressure operations. Some selected experimental results are presented. Although actual factors of safety against collapse requires knowledge of the individual test results, general trends for the degradation of collapse resistance due to prior service loading and the range in magnitude of the difference between actual and predicted collapse strength, are identified. Theoretical predictions of collapse resistance are based on existing formulations in which the ovality and axial loading appear as explicit parameters. Collapse predictions are also discussed in light of a newly proposed methodology submitted to the API under RP 5C7 as recommended practise for determining allowable collapse pressures on coiled tubing. A new methodology for accurate prediction of CT collapse that is based on measured stress-strain plots, is also discussed.
To Straddle or Not to Straddle -- The Inflatable Option
Authors: Mackenzie Gordon R. J.
Published: December 2007

This paper examines the use of coiled tubing deployed thru-tubing inflatable packers in a straddle configuration. Many times this straddle option can be used to prolong the life of a well without the time-consuming and resource-sapping operation of having to perform a complete well workover. Couple the resulting economics with the operational advantages of not having to kill the well and a completion in situ inflatable straddle option may and has offered operators in the global oil and gas industry a very real and viable option.

During the course of this paper the inflatable straddle option is examined and discussed as is the operational deployment and options of such a system. Running a single trip straddle and running a multiple trip down hole assembled system are highlighted. Four case histories will be disseminated to provide a balanced opinion on the effectiveness of such a system. The four case histories include a chrome system to match the already installed completion metallurgy and the highlighted wells will vary in geometry up to that of a horizontal gas well.

The paper goes on to discuss the longevity of such a system with at the time of submitting this abstract one of the featured systems having been in position in a producing environment for in excess of five years.
Using Mature Selective Re-Entry Technology to Manage Risk at Wytch Farm: A Case History
Authors: Brunnert David J.
Published: December 2007

This paper describes how the team at Wytch Farm met the challenge of drilling and completing selective re-entry laterals in an increasingly price competitive and performance-focused environment. One of the key elements in this success was the creative application and modification of existing technology. Utilizing predominantly mature technology, the team was able to proceed with confidence in the management of risk associated with new applications.
SPE/WPC/AAPG Resource Definitions as a Basis for Portfolio Management
Authors: Ross J G
Published: December 2007

In February 2000, three major international organizations, the SPE, WPC and AAPG jointly approved and published a significant document entitled Petroleum Resources Classification and Definitions1. This achievement represented a major step forward in the industry's attempts to improve the level of consistency in the documentation and description of resources that do not satisfy the criteria for reserves. The existing (1997) SPE/WPC reserves definitions2 were unaffected; the new definitions simply supplemented the 1997 definitions in order to cover the entire resource base. In addition to providing a single set of terminology for industry use, the document also provided a new classification system that was designed to facilitate the development of portfolio management systems by individual countries or companies.

The potential benefits of the SPE/WPC/AAPG classification system are twofold. Firstly, it provides the facility to expand the sub-division of project maturity, in order to classify projects on the basis of the work required (reflecting business decisions and budgeting) to move them towards commercial production and revenue. This ensures a continuous focus on the objectives of asset management, as well as providing the potential for a detailed classification of the resource base which illustrates clearly the balance of the portfolio and hence facilitates rational decisions on future acquisitions/divestitures.

The second benefit of the new system lies in the consistent approach to establishing a range of uncertainty, regardless of project maturity, which allows the very powerful tool of uncertainty tracking to be applied. Despite being first published by Arps3as long ago as 1956, this method is surprisingly little used. In practice, it is the only way to track estimates of recoverable volumes in a meaningful way, and to establish on an on-going basis the validity of the methods used to estimate those volumes.
Using Portfolio Analysis to Develop Corporate Strategy
Authors: Howell John I. , Tyler Peter A.
Published: December 2007

Every exploration and production company has the difficult task of deciding between a large number of competing oil and gas projects for future investments. Many companies are developing corporate strategies and making investment decisions without considering the relationship between the two. The result is a less than optimal financial performance and failure to meet corporate goals. The application of portfolio analysis within the strategy and investment stages provides a disciplined and systematic method of analyzing these relationships. Portfolio analysis can be used to develop and compare strategies given a "pool" of investments. Conversely, portfolio analysis can also be used to evaluate individual investments with respect to how they impact the company's ability to meet its strategy. Effective portfolio analysis requires high-quality data addressing such questions as: what assets are currently owned, which ones might be purchased, what stakes might be acquired, or what stakes might be developed in the near future? By taking on a particular economic project, is another opportunity missed that has a better net return? This presentation will illustrate the use of portfolio analysis to develop and compare alternate strategies that a company might pursue. The examples illustrate how projects and corporate performance measures interact and how the interactions create new opportunities for the corporation. The interactions can be quantified in terms of simple graphical summaries that allow decision-makers to compare alternate strategies and quickly assess the business performance trade-offs they will likely face when they select one strategy over another.
E&P Asset Value and Its Implications on Share Price
Authors: Jacobson Gregg A.
Published: December 2007

Every day E&P companies are confronted with opportunities and decisions, which will impact the value of the assets and enterprise that they manage. As the goal of publicly held companies is to maximize shareholder value, companies tend to respond by attempting to maximize Wall Street's preferred valuation metric of the day. Return on capital employed (ROCE), cash flow per share, reserve replacement and finding and development costs per BOE are used to judge the industry's performance over time; but the most significant determinant of both absolute and relative shareholder returns remains a company's ability to increase the value of its reserve base in an economic fashion. A multi-year study of 45 publicly held independent E&P companies establishes the strong correlation between reserve value and share price performance.
The Hydrocarbon Asset Valuation Solution: Making Major Investment Decisions 50X Faster, With Improved Accuracy
Authors: Ghazi T. Y. , El Rafie E. A.
Published: December 2007

Despite recent improvements, major investment decisions are often taken before the technical and business analyses are complete. Even when they are complete, managers are repeatedly left confused by mixed messages from the many disciplines involved. The result is avoidable costs and missed opportunities totaling hundreds of millions of dollars annually.

To solve this problem, we have re-examined all aspects of existing decision-making methods and have created a new way to facilitate crucial decisions much more quickly and clearly. This paper describes this new Hydrocarbon Asset Valuation (HAV) solution, and shows examples of how HAV can reduce cycle times by as much as 50X with improved accuracy and covering a wider range of uncertainties.

HAV consists of five elements: the team, the process, the tools, the room, and the data. The team includes all of the technical and business disciplines that impact the investment decision. The process enables a team to intensively collaborate for two to three weeks in one room to meet a common objective. They work in parallel, and produce several shared earth models, multiple reservoir simulations, numerous surface facility options, and dozens of marketing and business scenarios. This input ultimately converges on a critical few alternative development scenarios. The tools consist of simple yet powerful PC-based products for geoscience interpretation, reservoir simulation, surface facility configuration, economic scenario analysis and electronic documentation. This new software platform is far less expensive than conventional workstation-based products, and is much easier to use. The room is a large well-equipped room where the team meets and works through the process without interruption. Finally, the data includes a carefully extracted subset of the technical and business data to help characterize only those factors that impact profitability.

In one recent HAV example, a 35-person team fully articulated the value of an offshore block containing 51 assets in all phases of the life cycle in just two and a half weeks. This amounted to a 50X reduction in cycle time, with the improved accuracy that comes from synergy in all of the disciplines from seismic interpretation to marketing.
A Comparative Analysis of 12 Economic Software Programs
Authors: Wright John D. , Thompson Robert S.
Published: December 2007

One would expect that different economic programs should compute the same answers given the same problem statement. This hypothesis was tested by providing a very simple problem to a number of industry personnel using various software programs. The results show a significant and surprising difference in calculated values between the various programs. In 2000, a large project conducted by the Society of Petroleum Evaluation Engineers found that the differences arise from a combination of unstated assumptions; differences in interpretation of various parameters; different, but equally valid, treatment of factors such as discounting or escalation; and apparent misunderstanding of the problem statements. The results of the study indicate that there is a great need for standardization and communication regarding upstream economic calculation.
Integrated Optimization on Long Horizontal Well Length
Authors: Cho Hyun
Published: December 2007

Though the drainage area of horizontal reservoirs is increased with increase in horizontal well length, construction costs for drilling and completion also increase; this combines with other factors to negatively affect the overall economics of the horizontal well. However, no reliable standards are currently available that take into account the factors necessary for the determination of optimum well length for horizontal drilling.

This paper presents a methodology developed to obtain the optimum horizontal well length based on total economics as well as productivity index (PI) change associated with frictional loss effects in the long section of the horizontal wellbore. An integrated approach is proposed for quantitative analysis of the parameters affecting productivity and economics in order to achieve the overall optimum performance of a horizontal well project. This study shows that production is no longer proportional to the horizontal well length after a critical point. The critical point is calculated as a function of the length of the horizontal production section, flow rate, drawdown pressure, and other parameters. A step by step calculation procedure with examples is described with sets of graphical charts developed for illustrating the relationships between the various parameters. The results can be used directly to determine the optimum horizontal well length in multiple well projects.
Oil and Gas Property Marketing: To "e" or not to "e"
Authors: Marko William A. , Roberts Geoffrey G.
Published: December 2007

This paper is written not from the perspective of a service provider, but from the point of view of a seller of oil and gas properties. It is a pragmatic discussion of the application of e- business now and in the future for oil and gas property acquisitions and divestments (e-A&D). Its focus is not on specific technologies, but rather on how technology, judiciously applied, can improve A&D processes with the bottom-line measure being-an improved bottom line for oil and gas companies.
The Determinants of Oil and Gas Reserves Additions: Empirical Evidence from the U.S. Gulf of Mexico Outer Continental Shelf (OCS) Region from 1977 to 1998
Authors: Iledare Omowunmi O. , Pulsipher Allan G.
Published: December 2007

This paper presents a model of new petroleum reserves in the Gulf of Mexico OCS region from 1977 to 19981. The model has three distinct components: the effectiveness of drilling at finding reserves (drilling success rate), the effectiveness of successful drilling at adding new petroleum reserves (petroleum productivity rate), and the number of wells drilled to find new reserves (drilling rate). Each component is specified as a function of several competing factors to determine the extent to which each determinant affects reserve additions on the OCS. The model equations are estimated using OCS data on reserves and oil and gas wells drilled from 1977-1998. The empirical results indicate a statistically significant evidence of diminishing returns as drilling increases on the OCS. The estimated elasticities of oil and gas reserves additions with respect to resource depletion are both very elastic. However, the responsiveness of new oil and gas reserves to economic incentives is significantly inelastic for oil and gas reserves. The results show that the average impact of technical change, economic, resource depletion, and prospect highgrading on oil reserve additions is a net gain of about 9.2% per year between 1977 and 1998. However, the net annual average impact of these competing factors on new non-associated gas reserves is a decrease of 3.3 percent per year.
Synergy through Seismic Attributes in Reservoir Management-a Case Study
Authors: Mitra Partha P. , Singh Kharak
Published: December 2007

The heterogeneity within a reservoir is difficult to predict, but the subtle changes of the seismic wave shape within any sequence provide valuable information about the reservoir and are preserved in 3D seismic data. In order to optimize the understanding of the reservoir, it is necessary to integrate geophysical, geological, petrophysical, reservoir and production data. Diagnostic tests and studies such as production logging, reservoir saturation, build up, pressure and temperature are commonly studied at the time of reservoir management in a developing field but off late seismic attribute is being used as an additional tool for reservoir management. With the advent of sophisticated algorithms and faster machines, today it is possible to extract a number of seismic attributes from within a particular sequence. In a heterogeneous reservoir or in an area of poor well control, synergistic study of seismic attributes can help us investigate the lateral variations in the quality of the reservoir and improve the imaging of reservoir units, providing vital clues for placing infill wells and injectors.

In the present study an attempt has been made to decipher the reservoir behavior in one of the western offshore fields of India. The field in question is in production from carbonate reservoir over last six years. At places, poor reservoir facies have been observed within the pay leading to poor transmissibility in the area thus affecting the voidage compensation in the targeted zone. Using the conventional tools, it was difficult to map the lateral facies changes in between wells. Efforts have been made to calibrate seismic attributes with other relevant data in order to arrive at a good prediction of the reservoir quality.
The Influence of Variations in Porosity and Water Saturation on the Success of Hydraulic Fracturing: A Semi-theoretical Analysis
Authors: Widarsono B. , Muladi A. , Saptono F.
Published: December 2007

The objective of the study presented in this paper is to observe the influence of variation in rock petrophysical properties on fracture development. The analysis was primarily conducted using the combination of Continuum Damage Mechanics and the Perkins-Kern-Nordgren model (CDM-PKN). Essentially, the effect of porosity, water saturation, and shale contents on the two rock mechanical properties was studied using well-log data from an oil well in Central Sumatra (sandstone). Prior to the study the data was modeled using a combination of theory of elasticity, Gassmann theory of acoustic velocity propagation, and standard log interpretation. Laboratory acoustic velocity measurements were carried out to provide required data. The resulting model-relationships between sonic velocity, Poisson ratio, porosity, water saturation, and shale contents serve as input data for the study, on which the application of CDM-PKN model show that fracture length and width are mostly affected by variation in porosity. Variations in porosity between 11 % and 20 % may result in changes of up to 18 % and 100 % in fracture length and width, respectively. In contrast, variations in fluid saturation and shale contents (max. 10 %) exhibit less influence to the fracture growth. Nevertheless, depending on reservoir fluid and clay types, omission of the latter two factors in any hydraulic fracture design could complicate the mis-prediction.
Experimental Investigation into Revaporization of Retrograde Condensate by Lean Gas Injection
Authors: Luo Kai , Li Shi , Zheng Xitan , Chen Gang , Dai Zhijian , Liu Ning
Published: December 2007

Re-injection of produced gas is a common strategy to maintain pressure and to meet environmental regulations in gas condensate reservoirs and also to store gas until the market available. Although the best idea to prevent liquid loss is the full pressure maintenance development above the dew point pressure, the partial pressure maintenance process below dew point may be desirable for economic reasons, as the dew point pressures in some gas condensate reservoirs discovered in recent years is very high. In this case one major concern is whether gas cycling above the dewpoint is more profitable than below the dewpoint. Therefore, a knowledge of accurate condensate recoveries under two different development schemes is vital for making the accurate economic assessment and making final decisions.

To the end, a series of experiments have been done to investigate the condensate recovery based on the above two different development strategies and quantitatively determine the revaporization efficiency of retrograde condensate by lean gas injection. First the gas injection below the dewpoint was performed in a long-core apparatus. In order to calculate the quantitative amount of the revaporized condensate, other two parallel tests of gas injection above the dew point in a long core system and gas injection below the dew point in the PVT cell were conducted as a comparative basis. The actual gas condensate fluid and a long core system are employed here. The gas condensate used is rich and highly waxy. As a complete study, the routine phase behavior is first detailed, including constant mass expansion and constant volume depletion. An interesting finding in PVT cell shows that lean gas can not only effectively revaporize the intermediate but also C20 plus components. Comparison of the tests in long-core system illustrates that more condensate above the dewpoint is recovered than below the dewpoint. This is consistent with the conventional idea that the full pressure maintenance is superior to the partial pressure maintenance according to the condensate recovery. It should be noted that all the condensate recoveries reported here in three runs don't include the additional withdrawal of condensate in the slowdown process to abandonment pressure.
Upscaling of Flow Units for Reservoir Flow Incorporating Small-Scale Heterogeneities
Authors: Mikes D. , Barzandji O. H. M. , Bruining J. , Geel C. R.
Published: December 2007

Small-scale heterogeneities have a significant effect on the behaviour of fluid flow through a reservoir, since capillary forces trap the non-wetting phase in the high-permeable parts of a water-wet porous medium. An upscaling procedure must therefore be able to account for reservoir structure as well as for relative permeabilities and capillary pressures on the lamina scale.

For the geological model we propose a five-scale hierarchy with crossbed and subfacies as key elements: i.e. lamina scale → flow cell scale → flow unit scale → facies scale → reservoir scale. The reservoir model is a simplified version of the geological model with the flow cell and flow unit as building blocks. As an example we take a model of a meandering river with three types of flow units, viz. channel, pointbar, and floodplain. Each of these consists of one type of flow cell, i.e. trough crossbedding, longitudinal bedding and horizontal bedding, respectively (Fig. 2).

We propose a four-step procedure (Fig. 1): (1) Assignment of flow cells and flow units; (2) Calculation of capillary pressures and relative permeabilities of laminae; (3) Steady state flow simulation on flow cells; (4) Assignment of the ensuing effective phase permeabilities and capillary pressures to the flow units. The macro reservoir has the flow units as building blocks.

We use lamina permeabilities either from our strongly improved probe-permeameter or from a database. We calculate lamina scale capillary pressures and relative permeabilities using Brooks-Corey and Leverett-J function. Upscaling is realized using flow simulation: A microsimulation is performed on each flow cell for a number of water/oil injection ratios. The ensuing upscaled relative permeabilities are anisotropic and flow-rate dependent. They are used as the constitutive relations for the flow units, which is the next superior level to the crossbed.

This model and its properties are incorporated into the simulation of the full reservoir described in the SPE ninth comparative study on black oil simulators in heterogeneous reservoirs. We will ignore the rate dependence and use a constant anisotropy factor in each flow unit. The result shows that small-scale heterogeneities characteristic of the various flow cells must be specifically taken into account. Our procedure provides a method to accomplish this. The method is easy to implement.
A Comprehensive Study of the Relative Dielectric Permittivity in Porous Media
Authors: Garrouch Ali A.
Published: December 2007

This study investigated the effects of water saturation and wettability on the dielectric permittivity experimentally, using four-electrode impedance measurements, and theoretically, using models that account for the electrical double layer polarization.

Complex impedance measurements, performed on Berea sandstone and on Ottawa-sand packs in the frequency range 10 Hz to 1 MHz, indicated a linearly varying relative dielectric permittivity with water saturations above 50%. The rate of change of the relative dielectric permittivity with saturation decreased as the frequency increased.

The relative dielectric permittivity of water-wet samples was higher than that of the oil-wet samples at all water saturations. The difference was more pronounced as the saturation increased. The relative change was approximately 60% at a water saturation of 100%. To confirm these experimental observations, this study conducted simulations of rock wettability changes using a generalized Maxwell-Wagner model by varying the amount of ionic surface charge of rocks. In general oil-wetting agents react with the formation matrix by connecting their positively charged tails to the negatively charged silica surfaces, lowering the surface charge density. Simulations showed that there was about an order of magnitude difference in the relative dielectric permittivity as the rock surface charge changed by an order of magnitude. Both simulations and experimental results showed a trend of significant increase in the relative dielectric permittivity as the rock conditions changed from oil-wet to water-wet.
A Rule Induction Algorithm for Application to Petrophysical, Seismic, Geological and Reservoir Data
Authors: Deutsch Clayton V. , Xie YuLong , Cullick A. Stan
Published: December 2007

This paper introduces an algorithm for rule induction intended to provide new insights, improve the reliability and expedite the utilization of large petrophysical and geologic databases. Very large petrophysical, geophysical, and geological databases contain multiple data types, which must be interpreted for application in subsurface modeling. This paper presents a significant advance in discovering complex and even nontrivial data relationships from such databases.

Geoscientists are often challenged to predict subsurface lithologies and properties from multivariate relationships within large databases of core, wireline, and seismic data. Many data analysis techniques are used including histograms, parametric and non-parametric regression, n-dimensional histograms, cluster analysis, discrimininant analysis, principal components analysis. This paper introduces a new algorithm that seeks to discover "rule-like" relationships within the data that can be used to make predictions. The method is loosely derived from a data mining technology of classification.

Concepts of data attribute distinguishability and importance are introduced to assess the value of the data and the outcomes to predictability. The new theory, implementation details, and an application are presented. Current petrophysical, seismic, and geostatistical analysis benefit from the rule induction algorithm presented. Improved reservoir characterization and forecasting result.
Slug Development/Dissipation in an Inclined Pipeline with Changing Pipe ID
Authors: Lin Chew-Chen
Published: December 2007

Heavy oil recovery efficiency is strongly dependent upon quality and rate control of two-phase steam in a distribution system. One of the major challenges in steamflood operations is unequal steam phase-splitting at a pipe junction in the steam distribution system. As a result, the proper quantity of latent heat is not always effectively delivered to injection wells for optimized production. To overcome such a problem, a device referred to as the SpliTigator, is installed at branches in a steam distribution system. The standard SpliTigator was de-signed to perform best with a stratified flow regime, because water-vapor separation can be guaranteed if stratified flow arrives at the inlet of the SpliTigator. However, slug flow caused by a hilly terrain pipeline can occur at the inlet of the SpliTigator, practically eliminating its ability to mitigate the steam phase-splitting problem. A remedy can be implemented by modifying the piping configuration to alleviate severity of slug flow.

Experiments were conducted in the air-water flow loop to investigate slug development and dissipation along an inclined pipeline. Furthermore, tests were done for studying slug dis-sipation with increased pipe ID in the downstream section. Test data were analyzed by calculating slug frequency and slug length ratio as a slug development/dissipation index. Presented in this report are experimental results that illustrated sensitivity of slug dissipation to inclination angles and down-stream pipe ID. Evidenced in this study, modifying piping configuration by increasing downstream pipe ID and/or increasing downward inclination angle is a method of mitigating terrain induced slug before its arrival at the inlet of a SpliTigator.
Using Integrated Information to Optimizing Matrix Acidizing
Authors: Zhu D. , Radjadhyax N. , Hill A. D. , Montgomery C. T.
Published: December 2007

The technology of matrix acidizing has advanced dramatically over the last 30 years. Models have been developed to help understand and design the process, and methods have been applied in the field to monitor and evaluate treatments to achieve stimulation results as expected. Despite these advances, the success rate of acidizing is still low (estimated to be 50% - 70%), particularly in sandstones. When an acid treatment fails, not only will it waste the cost of the treatment, but also may possibly cause further damage to the well and lead to more severe problems.

Acidizing success strongly depends on the susceptibility of nearwell formation damage to removal by the acid solution. Thus, the nature of the damaging material and the depth to which the damage penetrates into the formation are critical properties to the success of acidizing treatments. Predicting the outcome of a treatment using models of the process depends most strongly on the description of the damaged region provided to the model. The dilemma we face is that we seldom have a detailed knowledge of the damage, but instead only a global measurement of the skin factor of the well. In this paper, we present an approach to improve the success rate of matrix acidizing by using integrated formation damage models, sandstone acidizing models, skin evolution models, and well production information. The theoretical prediction of the well response to an acid treatment is compared with a skin analysis result obtained during the treatment. Problems with inappropriate treating fluids can be identified clearly with increased skin factor during certain injection periods. Damage depth and damaged permeability can be re-evaluated from the characteristics of the well response to the acid. The skin analysis result can be confirmed with the well production or injection data after acidizing. Using the improved description of the damage obtained from the skin analysis of treated wells, the simulation model can then be used to redesign acidizing treatments to achieve better results.
Formation Pressure Integrity Treatments Optimize Drilling and Completion of HTHP Production Hole Sections
Authors: Sweatman Ron , Kelley Scott , Heathman James
Published: December 2007

Insufficient borehole pressure integrity (BHPI) is a significant drilling challenge in deep, high-temperature, high-pressure (HTHP) wells in south Texas, as it is in many wells. Shales and/ or sands weakened by depletion, leaking faults, or unfavorable rock properties result in lost returns when mud weights are close to pore pressures. In one field, short (~50 ft) transitions from normal (11 lb/gal) to overpressured (17.5 to 18.0 lb/gal) Frio formations compound the severity of this challenge. Setting casing to isolate normal-pressure from high-pressure zones can be problematic if faults exist at the casing shoe and/or the cement job does not provide a good hydraulic seal. In one case, the intermediate casing shoe failed to test, and conventional cement squeezes were unable to correct the problem. In the productive portion of the well, preventing skin and or formation damage in an interval that had a wide range of pore pressures (8.5 to 17.8 lbm/gal), was a major concern with any treatment option to increase borehole integrity.

This paper describes successful applications of new BHPI treatment materials and methods for increasing borehole integrity. BHPI treatments have allowed higher drilling and cementing circulation rates. This has helped optimize drilling performance and improve well conditions during cementing operations, which has resulted in improved primary cementing success. It has been suggested that skin damage in the zones of interest can be minimized since BHPI treatments can be designed and targeted to only enter areas with low BHPI. In one case, a BHPI treatment entered a low-pressure productive interval, which, after a planned stimulation program, did not seem to affect production performance. In another case, after BHPI treatments helped increase wellbore integrity, the productive interval in one well was successfully cemented without requiring a drilling liner, which would have limited completion flexibility.

A theoretical rock mechanics model is discussed to help explain how the new BHPI treatments can rapidly and substantially increases the pressure integrity of holes located across both sand and shale formations. Minor BHPI filtrate invasions during tests in high and low-permeability sandstone cores should explain why the new BHPI system also limits formation damage.
Development and Application of Surfactant-Based Systems for Treatment of Wells Drilled with OBM
Authors: Giard-Blanchard Claire , Audibert-Hayet Annie , Dalmazzone Christine
Published: December 2007

Wells drilled with oil-based muds can suffer from severe damage which decreases their overall productivity. During drilling, mud solid parts tend to form an external and internal filtercake along well bore through filtration, while liquid part (filtrate) tends to leak off into the formation. Clean-up process is then necessary to restore the productive zone to a nearnatural state before production. Chemical treatment is often used to break external cake and to wash-off damage zone around well bore, so that formation recovers its fluid transfer properties (water, oil).

This paper focuses on the development and application of surfactant-based systems for treatment of wells drilled with oil-based muds. Aqueous based systems are widely used in such cases to effect significant production increases, but they create an additional damage which may even block oil production. A promising issue would be to use a surfactant-based system in a non-pollutant organic base to limit in situ formation of emulsion and water saturation around the well bore.

Though, our research methodology aims to select an organic-based surfactant system able to break the cake formed by filtration of a given oil-based mud system. The demulsifying formulation should be able to bother interface surfactants stabilizing effect to allow water droplets coalescence inside the cake. Through breaking emulsion inside the cake, surfactants may decrease cake cohesion and bore adherence. Careful choice may help preventing the system composed of filtrate, reservoir fluids and treatment fluid from forming a stable emulsion inside the porous medium, which could block oil production. Laboratory data are presented showing the relative effects of the organic phase surfactant system and of a conventional commercial treatment on cake destruction and productivity recovering. Results are held by a precise experimental methodology combining Differential Scanning Calorimetry and Cryomicroscopy. Both techniques characterize emulsion stability and destabilization as a function of wellbore parameters (contact time, overbalance pressure...).