bluuebunny/crossref_metadata_2025 huggingface dataset:
High-Density Invert-Emulsion System with Very Low Solids Content to Drill ERD and HPHT Wells
Authors: Nicora Luigi F. , Pirovano Pierangelo , Blomberg Nils , Taugbøl Knut
Published: December 2007

The paper describes the laboratory development of a new Low Solids Oil Based Mud System (OBMS) with a very high specific gravity (2.04 SG; 17 ppg) for high-temperature and high-pressure applications. The system can also be applicable as solid free oil based mud with very low viscosity at densities up to 1.52 SG, especially suggested for Extended Reach Drilling Wells. The main goals of the new system are:

Optimization of fluid rheology by reduction of the solids contents in the mud. Temperature and system stability at 170 °C.

The objectives have been pursued in the following ways:

– by using a very heavy brine as the internal phase; – by decreasing the oil / brine ratio; – by using a weighting agent with higher density than barite.

In this way, the amount of weighting solids which needs to be added can be drastically reduced to even below 22% v/v for a 2.04 SG mud, compared to 35% v/v as in traditional oil based muds. Also the PV values have been reduced from typically round 60 cP to even below 25 cP.

The addition of new components to the system has lead to the need of a new emulsifier package, which has been optimized with the development of a primary emulsifier and a wetting agent based on innovative chemistries.
Calculating Variation of Fluid Density in Near-Wellbore Environment and Its Application to Density/Porosity Calculations
Authors: Hamouda A. A. , Van De Verg P. E. , Enderlin M. B.
Published: December 2007

Knowledge of fluid density within the pore volume investigated by gamma-gamma density logging tools is necessary to accurately calculate porosity. As porosity increases the effect of fluid density on density porosity estimates increases. The algorithm presented here calculates "true fluid density" as a function of fluid saturations, hydrocarbon composition, temperature and pressure. The algorithm can handle mixtures of oil, gas, and water at different salinities, temperatures, and pressures. More accurate fluid densities are used to improve accuracy of porosities derived from gamma-gamma density measurements.

Because the gamma-gamma density tool responds to some function of "electron density" and not the "true density", the concept of "apparent density" was developed during the 1950's for quantitative interpretation of gamma-gamma density logs. "True density" is related to "electron density" by the ratio (Z/A) of the atomic number (Z) to the atomic weight (A). The ratio (Z/A) varies with the fluid composition, hence the accuracy of calculated densities is influenced by fluid composition. The algorithm developed in this paper follows two paths. In one path, only stock-tank oil density is known and in the other path, the composition of the oil and gas are known. In both paths, water composition (salinity or total dissolved solids) is required.

The paper includes a sensitivity study for the calculation and a field example in which this method is applied to a high porosity oil field where accurate density porosity calculation is hindered by fluid density variation related to water injection, depletion, large temperature anomalies, and drilling mud type. Results from density porosity calculations using "apparent fluid density" are compared with core porosity measurements and with other density log porosity calculations. Density porosity based on "apparent fluid density" matches core results more closely than other calculations.
Studying the Mechanisms of Crude Oil Pour Point and Viscosity Reductions When Developing Chemical Additives with the Use of Advanced Analytical Tools
Authors: Tung Nguyen Phuong , Phong Nguyen Thi Phuong , Long Bui Quang Khanh , Thuc Phung Dinh , Son Tong Canh
Published: December 2007

Laboratory investigations of paraffin deposition process and the remarkable changes in the crystal structure of waxes resulted in the development of several copolymer paraffin crystal modifiers. Their mixtures with surfactants have caused strong viscosity reduction in Various Vietnam high paraffin crudes.

The changes in form and size of paraffin crystals due to co-crystallization between effective pour point-viscosity depressants and crude oil waxes, were investigated and the results were recorded by means of scanning electronic microscopy (SEM). The mechanisms of pour point and viscosity reductions were examined using Infrared and Raman spectroscopes. The advantages and disadvantages of these tools were noted.
Lab Testing and Field Application of a Large-Scale Acetic Acid-Based Treatment in a Newly Developed Carbonate Reservoir
Authors: Nasr-El-Din H. A. , Lynn J. D. , Taylor K. C.
Published: December 2007

A large-scale acetic acid-based stimulation treatment was developed to remove drilling mud filter cake in vertical wells in a newly developed carbonate reservoir. The wellbore stability of this weakly consolidated carbonate formation can easily be reduced by contact with HCl-based acids. Extensive lab testing had indicated that the formation is mechanically weak, becomes brittle upon contact with acids and produces large amounts of fine particles that can cause severe damage. Furthermore, a chloride-free acid formula was required to minimize interference with the pulsed-neutron logs (PNL). A special acid treatment was needed to remove the damage while maintaining the integrity of the formation.

Several tests were conducted in the laboratory to evaluate both regular and emulsified acetic acid and non-acid formulae (mainly EDTA). Initially, two acid formulae were selected for field application. The first used 10 wt% acetic acid in an emulsified form, while the second formula was based on 10 wt% regular acetic acid in combination with additives. Further lab and field-testing indicated that the emulsified form might pose a problem in the presence of fine inter-matrix dolomite particles. Therefore, the treatment performed in the field focused on the use of 10 wt% acetic acid with several waterwetting agents (mainly surfactants and mutual solvent).

The acetic acid treatment was applied in five vertical wells in this field using a coiled tubing unit. Pressure build-up tests after the treatment indicated that the acid was successful in removing the filter cake in all cases. Neither fine particles, nor any type of emulsion was noted in the well flowback samples. However, well productivity after the treatment was found to be a strong function of the lithofacies of the formation (e.g., chalk versus packstone). Wells with high reservoir quality rock (i.e., packstones with a permeability of 20–30 mD), demonstrated excellent pressure response after the treatment. Flowing wellhead pressures were increased significantly. Wells with low reservoir quality showed a moderate increase following the treatment.
E&P Decision Support System for Asset Management - A case study
Authors: Floris F. J. T. , Peersmann M. R. H. E.
Published: December 2007

In recent years the emphasis in the development of new methodologies and tools has been on integration of data and applications. The new challenge lies in using the data generated by these packages to support the decision making process. In a joint industry project NITG-TNO have developed an E&P Decision Support System which helps the E&P asset manager to make more informed decisions regarding the exploration and development of hydrocarbon assets at any given moment in time. In the E&P DSS the data and information from earth modeling, surface engineering and economics are combined into an integrated asset model. It is then possible to place the technical decisions in an economic framework and come to a more transparent and auditable decision making process based on more diverse sources of information.

The asset manager can define scenarios representing the key decision and uncertainties for the asset. From the defined scenarios a scenario tree is built automatically. Within each combination of scenarios, full probabilistic assessment of the decision indicators in the asset model is still possible. The assessment can either be done based on Monte Carlo analysis using fast evaluation models, or by loading data for multiple stochastic realizations generated by external software. The probability distributions for the scenarios are then merged to form the total uncertainty. The options for the key decisions are then evaluated using the full probabilistic assessment. Finally, the sensitivity of the decisions on the input parameters can be analyzed.

The method is demonstrated for a typical development decision. In the case study, decisions must be made for the best type of surface facilities and wells, and whether water injection is preferred. Key uncertainties are the conductivity of a fault, the strength of the aquifer and the oil price. Application of the methodology allows the assessment
Integrated High Technology of Formation Evaluation and Directional Drilling – Key Inputs for Well Placement in a Complex Structural Environment –– A Case Study
Authors: van den Bosch R. H. , Meier L. P. , Rohde U. , Maggs D.
Published: December 2007

A directional sour-gas well achieved its objective, a long horizontal reservoir penetration, after the third attempt. The 431 m penetration is a record in this complex Zechstein Stassfurt carbonate area. Key to the final success was state-ofthe-art information derived from Logging-While-Drilling (LWD) tools, fast development of a new geological model and modern directional drilling techniques.

The 70° slanted well reached top of reservoir on schedule but exited after 40 m. This was unexpected because the original model showed a possibility of 600 m pay. A side-track was drilled with less deviation, but left the target after 30 m. The well would not have been economic with such a short pay interval.

Although LWD-data indicated that porous and gas-bearing reservoir had been encountered it was unclear from standard log information why reservoir thickness was reduced so dramatically. An innovative interpretation came from the use of density-image analysis. Continuous azimuthal density measurements of the wellbore wall allowed structural interpretation similar to a resistivity image sonde. With this approach a normal fault was identified which cuts off the lower part of the reservoir, and its orientation determined. This information formed the basis for a new geologic model.

The challenge for the third hole was to construct and drill a well path with an extended pay zone without exceeding the constraints of the new geologic model. The result was a ‘designer-well-path’ with rapid changes in deviation and azimuth. This had not been attempted before at depths around 3000 m TVD and a hole diameter of 5 7/8". The second sidetrack encountered 431m of reservoir section and the well was successfully completed.
Integrated Uncertainty Assessment for Project Evaluation and Risk Analysis
Authors: Corre B. , Thore P. , de Feraudy V. , Vincent G.
Published: December 2007

The main technical contribution of the study presented in this paper was, by an integrated assessment of uncertainties in geophysics, geology and reservoir engineering, to provide a rational basis with risk analysis for the management of uncertainties in the development of the field and therefore better decision making.

The objective of the study was to integrate the uncertainties identified on the Lambda Lower & Upper reservoirs and to quantify their impact on Gross Rock Volume (GRV), Oil Originally in Place (OOIP), recoverable reserves and production profiles.

The work was carried out in five main steps:

Determination of the distribution of the GRV. Building of a representative cloud of geological full field models (1000 equiprobable models) integrating geophysical, sedimentary and petrophysical uncertainties. Determination of the distribution of OOIP. Sorting and selection of a representative subset of reservoir models to quantify dynamic uncertainties. Modelisation by means of experimental design of the impact of dynamic uncertainties on the representative subset of geological models. Integration of static and dynamic uncertainties to assess statistical distributions of recoverable reserves, production profiles and plateau duration using experimental design technique coupled with multi-variable regression and Monte-Carlo simulations.

The following results were obtained:

– probability distributions of GRV – probability distributions of OOIP for each reservoir (Lower & Upper) and for each zone of the Upper reservoir – probability distributions of recoverable reserves and production profiles – probability distribution of production plateau duration – probability estimation of different models, associated with quantiles 10, 50 and 90 of the OOIP and Np distributions – measure of the weight of the main uncertainties on the OOIP and reserves.
Improvement and Application of a Mineral-Dispersion System to EOR
Authors: Li Jiyong , Wang Lushan , Yuan Mou , Shao Hongyun , Ji Shujie , Wang Yefei
Published: December 2007

This paper deals with the improvement and application of a new technology to EOR. This technology is applicable to high salinity and severe heterogeneity reservoir, especially to high temperature reservoir.

The essence of this technology is to decrease the water cut of production wells and attain the result of oil production and recovery enhancement by injecting a mineral dispersion system. According to lab test, this colloidal dispersion system is a pseudoplastic fluid with temperature tolerance, shearing resistance, stability and low cost. The lab experiment result shows oil recovery is improved by 8–10%.

The information of lab study and field application relative to this technology was presented at the 1999 SPE International Symposium on Oilfield Chemistry. As to the defect of this technology, lab study was improved. A new oil displacement system, can be mixed by formation water and possesses strong salt resistance, was presented and applied in oilfield.

Pilot area lies in Shengtuo Oilfield Tuo 7 block, including 5 injection wells and 10 corresponding production wells. The viscosity of aimed formation oil was 13–24 mPa.s, the temperature was 80, the salinity of reservoir brine was 15000mg/L and well spacing was 200–500m. The result was observed that production wells were effective after a month injection during the successive injection of this dispersion system for 6 months. Water cut of typical effective well was decreased by 10%. Oil production per day increased 9 ton.

Pilot test shows that this technology has better enlarge commercial application potentiality and economic value. It will be applied in Shengtuo Oilfield on great scale in the future.
Evaluating Asphaltene Inhibitors: Laboratory Tests and Field Studies
Authors: Yen Andrew , Yin Y. Ralph , Asomaning Samuel
Published: December 2007

A producer in Alaska had been experiencing asphaltene deposition problems in one well of a dual string completion, producing from two zones. Laboratory tests performed on both dead and live oil samples identified inhibitor A as the most effective chemical for this well. The field performance of inhibitor A was monitored by a wellhead side stream filter plugging loop. Results from laboratory tests and a field trial are presented. In this paper the correlation between lab data and field performance shows that predictive lab tests can successfully select an asphaltene inhibitor for field applications.
Effect of the Spreading Coefficient on Two-Phase Relative Permeability
Authors: Araujo Y. C. , Araujo M. , Guzmán H. , Moya G.
Published: December 2007

Understanding the dynamics of multiphase flow is essential for optimizing enhanced oil recovery processes. One of the properties that describes the behavior of the fluids in the reservoir is the relative permeability. Despite the development of empirical functional forms and the gathering of a growing body of experimental data, the subject lacks a fundamental basis based on the analysis of the configuration of the fluids at the microscopic scale. In this direction, we have addressed a systematic study of the effect of the spreading coefficient on two-phase relative permeabilities for systems of known wettability.

We have developed a method to evaluate the spreading coefficient for solid/liquid/liquid and solid/liquid/gas systems. Samples used for evaluation of the effect of the spreading coefficient on relative permeability were chosen within a wide range of wettability conditions which include water wet, mixed and oil wet samples. Relative permeability was measured using the dynamic method at reservoir conditions. It is found that oil recovery and relative permeability are higher for spreading than for non-spreading conditions. This information is relevant for gas drainage displacements. We comment on the fluid distribution for positive and negative spreading energy and the effect on residual oil saturation.
Reduction of Fluid Wastes in Gas Production and Storage Operations
Authors: Kozera Greg , Amick Paul , Toothman Rick
Published: December 2007

Wastes are generated during all oilfield and gas-field operations. Produced fluids make up the largest volume of generated waste, and any material used for drilling, treating, or reworking oil and gas wells canbecome part of the waste stream. In some cases, the cost of proper waste disposal can be significant. However, the cost of fines, cleanup, litigation, and a tarnished corporate image associated with improper waste disposal is far greater.

To remain competitive and profitable, companies must control their costs. Workover and fracturing fluids can be reused, or they can be disposed of on-site for minimal cost. However, these fluids must sometimes be shipped to off-site treatment facilities at great expense to the gas-production or storage company. This paper discusses ways of reducing the volume of produced fluids and used fracturing fluids that must be disposed of. We present a case history on (1) reusing fracturing flowback fluids and produced fluids and (2) redesigning fracturing treatments so that they use less fluid to provide the same results.
Drilling Fluids Design and Field Procedures to Meet the Ultra Deepwater Drilling Challenge
Authors: Camero Charles B.
Published: December 2007

This paper focuses on the potential problems facing the operator inultra-deepwater exploration and development drilling. A practical review ispresented of world-wide deepwater drilling fluid experience with examples ofsuccessful technology application. Remote locations, high rig costs andenvironmental constraints - coupled with low fracture gradients, long risersand the associated risks of shallow water flows, mud losses, and gas hydrateformation - present significant challenges to the industry. These potentiallytroublesome drilling conditions are addressed along with the technologies thatare being developed to overcome them.

Critical drilling fluid success factors, in the planning and construction ofan ultra-deepwater well, are discussed. These include the drilling fluidselection process, rheology optimization, downhole hydraulics modeling and gashydrate prediction. The latest techniques in monitoring drilling fluid andwellbore behaviour while drilling a well are also introduced.

Introduction

The definitions of deepwater and ultra-deepwater have tended to vary bothgeographically and chronologically as drilling and completion operations haveadvanced into deeper and deeper waters. Depending on the geographical location, deepwater is variously defined as water depth greater than 400–500 metres andultra-deepwater greater than 1500–1700 metres.

Deep-water operations involve some unique issues in offshore drilling whichcan pose significant additional challenges to the operator. From the drillingfluids perspective, these include:High rig cost and remote locationLarge circulating fluid volumesShallow water flowsLow mud temperature in the riser and pitsLow fracture gradients and narrow mud weight/fracture gradient windowsHole and riser cleaningEquivalent Circulating Density (ECD) control and potential for lostcirculationGas hydrate risk

In addressing these deepwater challenges, environmental and safety issuesare of paramount importance. The following technical issues are frequently alsoof concern:

Well Planning

In deepwater drilling, the selection of a stable drilling fluid, which canbe left in the hole for extended periods, is essential. Inhibitive fluids withlow dilution and consumption rates are of considerable benefit in minimizinglogistics and supply problems. With typical riser volumes from 160 to 500m3 (1,000 to 3,000 bbl) and circulating volumes from 400 to 800m3 (2,500 to 5,000 bbl), any requirement for massive dilutionvolumes must be avoided.

Solids control efficiency is paramount to control low gravity solids (LGS)and minimise dilution volume. Optimal solids control equipment would includefour linear motion shale shakers, ideally preceded by four scalping shakers, plus two high speed centrifuges in parallel. One or two drier shakers forsynthetic or oil base fluid recovery may also be required.
Offshore Operating Costs for Marginal Fields: "Selecting The Best Operating Strategy"
Authors: Steube Chuck
Published: December 2007

This paper outlines a methodology for the foundation and selection of an operating plan for FPSQ field developments. This methodology can also be applied to any onshore or offshore oil or gas field development. The primary consideration for this methodology involves integration of all involved parties during the conceptual engineering phase of field development. This should include the following:

Company integration between the different technical disciplines such as ( Drilling, Engineering both Reservoir, Well and Process, Operations, and others such as Marine or Pipeline) Integration of Partners within the project team Integration of Regulatory Bodies early on in the development phase Integration of Contractors to identify the potential for shared service agreements which increase equipment utilization and result in significant cost savings

This approach lends itself to viewing the project from a complete field life cycle. The methodology then can be used as a road map to identify operating cost ranges and the most cost-effective approach for field development.
IMPES Stability: The CFL Limit
Authors: Coats K. H.
Published: December 2007

This work considers cocurrent, three-dimensional, single-phase miscible and two-phase immiscible, hyperbolic flow in a general grid, structured or unstructured. A given grid block or control volume may have any number of neighbors. Heterogeneity, anisotropy, and viscous and gravity forces are included, while tensor considerations are neglected. The flow equations are discretized in space and time, with explicit composition and mobility used in the interblock flow terms (the Impes case).

Published stability analyses for this flow in a less general framework indicate that the CFL number must be < 1 or < 2 for stability. A recent paper reported non-oscillatory stability of one- and two-dimensional Buckley-Leverett two-phase simulations for CFL < 2. A subsequent paper claimed to predict this CFL < 2 limit from a stability analysis. This work gives a different reason for that stability up to CFL < 2.

This work shows that the eigenvalues of the stability matrix are equal to its diagonal entries, for any ordering scheme. The eigenvalues are in turn equal to 1-CFLi, which leads to a conclusion of an early paper that CFL < 1 is required for non-oscillatory stability. CFL values between 1 and 2 give oscillatory stability. In general, our Impes simulations require the non-oscillatory stability ensured by CFL < 1.
Full-Tensor Multiphase Flow Simulations With Applications to Upscaling and Discrete-Fracture Models
Authors: Yang Yi-Kun , Deo M. D.
Published: December 2007

The permeability tensor in three-dimensional space is given by a symmetric and positive definite matrix. Advances in reservoir characterization and geostatistics facilitate the construction of fine scale reservoir images. Some degree of upscaling is almost always required to make the problem computationally amenable. The upscaled permeabilities calculated thus are, in general, full tensor quantities. Homogenization of discrete-fracture domains also leads to full-tensor permeabilities of the equivalent permeability field. A formal infrastructure to treat full-tensor permeability field has been developed in this paper along with an understanding of the impact of such a field.

A novel co-ordinate transformation scheme is proposed where the cross permeability terms are eliminated and an equivalent diagonal-tensor permeability field is generated. The multiphase flow equations are solved using the finite-element discretization. Galerkin finite element method is employed and the model equations are solved fully implicitly.

First, it is demonstrated that full-tensor representation is necessary to preserve the flow characteristics in the fine-grid domain in both the cases. It is then shown how the computational complexity of the full-tensor simulation could be reduced using the transformation scheme. The novel transformation scheme thus offers the computational simplicity of the diagonal-tensor representation, while preserving the rigor of the full-tensor approach. The effect of using the full-tensor field from homogenized fracture permeabilities is described.
Simulation of Vertical Fractures and Stratiform Permeability of the Ghawar Field
Authors: Phelps Robert E. , Strauss Jonathan P.
Published: December 2007

It has long been known that well intersections in the Ghawar field show thin intervals of extremely high productivity. These can be related to high permeability layers (stratiform features) or to sub-vertical faults and fractures. This paper discusses the characterization of these features and their inclusion in field scale simulation model. All high permeability features (both matrix and fracture related) are incorporated into the "fracture" component of a dual-porosity dual-permeability simulation. Fine grid modeling is used to validate the approach and to gain an understanding of the physical processes taking place within the reservoir. Practical considerations and difficulties encountered in setting up a large-scale (16 x 17 km) sector model using the DPDP properties are discussed. Results for several runs that include 40 years of production history show that the methodology has the potential to improve simulation modeling of this field.
Integrated Modeling of Geological Heterogeneity and Fluid Displacement: Smørbukk Gas-Condensate Field, Offshore Mid-Norway
Authors: Brandsæter I. , Ringrose P. S. , Townsend C. T. , Omdal S.
Published: December 2007

The Smørbukk Field comprises a deep, very heterogeneous reservoir with variable fluids (gas condensate to light oil). This study presents a series of sensitivity studies to evaluate the effect of different geological parameters and development options on oil production and gas oil ratio within a sector of that field. The black-oil Eclipse reservoir simulator is used to represent the gas displacing oil behavior of this rather complex reservoir. Constant production rates and pressure controls are assumed. Detailed geological models of sedimentary and structural heterogeneity were used to define reservoir simulation models with upscaled permeabilities and relative permeabilites. Displacement and transmissibility reduction across faults were explicitly modeled and compared with simpler assumptions. The main performance measure used is oil recovery and GOR at the five year production point. Important interactions between geological assumptions and fluid rates and pressures were identified and used to identify the most promising production strategy.
Takula Field: Data Acquisition, Interpretation, and Integration for Improved Simulation and Reservoir Management
Authors: King G. R. , David W. , Tokar T. , Pape W. , Newton S. K. , Wadowsky J. , Williams M. A. , Murdoch R. , Humphrey M.
Published: December 2007

Current reservoir characterization techniques allow for geostatistical models on the order of several million grid cells. In general, these models are developed from static data, such as open-hole log data and core data. Recent developments in reservoir characterization have allowed for the incorporation of some dynamic data, such as pressure transient data and 4D seismic data, into these geostatistical models.

During the day-to-day management of large oil fields, data are often acquired from sources other than those listed above. These data include cased-hole logs, production logs, and wireline pressure data. These data are generally acquired to aid in the design of workovers, plan profile modification programs, and perform other routine reservoir management tasks. Due to the frequency in which these data are acquired, they represent dynamic reservoir data. When these data are considered in a reservoir simulation study, they are typically incorporated during the history match phase. There are, however, instances when these data are incorporated during other phases of the study.

The Takula Field is the largest producing oil field in Angola. This paper discusses data acquisition and interpretation in the Upper Vermelha Reservoir of the Takula Field and its integration into the reservoir simulation model. What sets this case study apart from other case studies is the detail in which the "routine" dynamic data were integrated into the reservoir simulation model (during all phases of the study) and the detail in which these data are used to maintain the model. Topics to be discussed include:

Use of injection well PLT data during the history matching process (History matching of injection wells is a topic rarely discussed in the reservoir simulation literature). Integration of PLT, PNC, and C/O logs into water encroachment and CHPF (current hydrocarbon-pore-foot) maps. These maps were used during the history match phase of the study to match saturations on a flow unit basis. In addition, these maps are updated on an approximate six-month basis and provide the framework for checking measured frontal advance and simulated frontal advance during the prediction phase of the study. A novel approach of using cased-hole gamma-ray logs to monitor the flood front advancement of a peripheral waterflood. When appropriate, this method also aids in the determination of whether produced water is formation water or injected water and provides a dynamic check on the internal consistency of the reservoir zonation (i.e., internal reservoir "plumbing"). Use of wireline pressure data to estimate the tolerance in history matching static well pressures obtained from stratified reservoirs. Use of PNC and C/O log data to supplement core end-point saturation data and provide limits for end-point saturation adjustments during the history match.
Full-Field Modeling Using Streamline-Based Simulation: 4 Case Studies
Authors: Baker R. O. , Kuppe F. , Chugh S. , Bora R. , Stojanovic S. , Batycky R.
Published: December 2007

Modern streamline-based reservoir simulators are able to account for actual field conditions such as 3D multi-phase flow effects, reservoir heterogeneity, gravity and changing well conditions. A streamline simulator was used to model four field cases with up to 400+ wells and 150,000+ grid-blocks. History match run times were about 1 CPU hour per run with the final history matches completed in about 1 month per field. In all field cases, a high percentage of wells were history matched within the first 2-3 runs. History matching fields with a large number of wells is quite different than matching simulation models with only a few wells.

Streamline simulation not only enables a rapid turnaround time for studies, but also serves as a different yet valuable tool in resolving each of the studied fields' unique characteristics.

The primary reasons for faster history matching of permeability fields using 3D-streamline technology as compared to conventional finite difference techniques are:

Streamlines clearly identify which producer-injector pairs strongly communicate (flow visualization). Streamlines allow the use of a very large number of wells thereby substantially reducing the uncertainty associated with outer boundary conditions. Streamline flow paths indicate that idealized drainage patterns do not exist in real fields. It is therefore unrealistic to extract symmetric elements out of a full field. The speed and efficiency of the method allows the solution of fine scale and/or full field models with hundreds of wells. The streamline simulator honors the historical total fluid injection and production volumes exactly as there are no drawdown constraints, initially. Easy identification of regions that require modifications to achieve a history match. Streamlines provide new flow information (i.e., well connectivity, drainage volumes, and well allocation factors) that is not possible to derive from conventional simulation methods.
Streamlining Abandonments for Cost Reduction
Authors: Woody Fred
Published: December 2007

Total idle well population in the United States, both regulated and unregulated, currently is estimated to be approximately 1,000,000 wells. Conventionally, creating an inventory, and designing and implementing abandonment programs where appropriate has required substantial manpower. Today's computer software and portable hardware has created an opportunity to better design, implement and track abandonment programs. This paper discusses the development of a field available package, which allows real time delivery at the field level while generating essential reports and tracking process.

This methodology was required to meet the following criteria: Reduction of cost by 30%;Minimal reliance on production personnel;Real time delivery of progress reports; and,Prompt delivery of regulatory reports.
Implementing Waste Management Strategies
Authors: Ramnath Kelvin , Dyal Shyam
Published: December 2007

The activities of finding, producing and refinery petroleum, can impact the environment, and the greatest impact arises from the release of wastes into the environment in concentrations that are not naturally found. These wastes include hydrocarbons; solids contaminated with hydrocarbons and other pollutants, water contaminated with a variety of dissolved and suspended solids; a wide variety of chemicals and gaseous emissions contaminated with toxic chemicals.

The Petroleum Company of Trinidad and Tobago Limited (PETROTRIN), have developed a number of major capital intensive waste management programmes to ensure the Company's operations have minimal adverse impacts on the surrounding environment.

These programmes are: ❖Construction of three secondary waste water treatment plants.❖Conversion of barometric condensers to surface condensers at two vacuum distillation units at the Pointe-a-Pierre refinery.❖Segregation of storm water drainage from process oily waste water.❖Bioremediation of 126,000 barrels of oily wastes stored in two earthen pits at Pointe-a-Pierre refinery.❖Bioremediation of approximately 18,000 barrels of oily wastes stored in two earthen pits at Parrylands, Point Fortin oil field.❖Installation of three Sulfa-Treat plants for treatment of hydrogen sulphide gas in production operations.❖Installation of a Sulphur Recovery Unit at Pointe-a-Pierre refinery to convert hydrogen sulphide gas into solid sulphur.❖Installation of internal floating roofs at five product storage tanks at the Pointe-a-Pierre refinery.

Steps are being taken by the Environmental Management Authority to strengthen legislation in the near future. Major capital improvements in the implementation of waste management systems by Petrotrin have resulted in reduced impacts on the environment. The overall effort of these proactive programmes has been worthwhile due to the enormous increase in the understanding of our environment and the improvements being achieved.
Reducing the Environmental Impact by Replacing Chemistry with Physics
Authors: Sørgård Eirik , Villar John P.
Published: December 2007

The offshore E&P business is becoming increasingly focussed on environmental issues brought on in part by an increased awareness of the impact the industry has on the environment and the sensitive areas being explored. The fertile fishing waters in the Norwegian Sea are governed by some of the strictest environmental legislation that exists for offshore oil drilling. Incentives to minimize the exposure of chemicals to the environment have been sought after by operating companies in these waters. The work described within highlights advancements made in minimizing the chemical requirements for cement slurries used in such sensitive waters.

This paper outlines efforts which were put forth to not only reduce the environmental impact by dramatically reducing the requirement for chemicals but also to provide a technically superior cement slurry via capitalizing on the particle physics of the dry components in the cement blend.
HSE Issues: One Company's Effort To Continuous Improvement
Authors: Ferraro M. , Fassina P. , Blotto P.
Published: December 2007

ENI-Agip Division is actively working to develop processes increasingly compatible with the environment and health and safety principles, aiming at the best care of HSE aspects for all company's activities.

The effort expended to continually improve prevention and protection systems is considerable. At present, Agip Division is actively involved in projects with universities and research institutes as well as associations representing oil companies, as shown by the large number and high level of ongoing innovative and R&D projects.

A lot of activity concerns ongoing scientific research projects focused on management of consequences arising from environmental emergencies, definition of monitoring and techniques management systems for clean-up activities, coupling and uncoupling problems related to subsidence modeling and forecasting, etc. Also, the evaluation of accidental consequences after fire, explosion and blowout events is being actively followed. The same approach is adopted in the corrosion management where a combination of the estimated likelihood of failure due to corrosion and the consequence of this failure is assumed to define the level of risk.

The paper deals with all the innovative projects presently ongoing and intended to significantly improve Agip's HSE performance in the near future.
Environmental Management Plans Required for Financing International E&P Projects: From Development to Implementation
Authors: Snow B. L. , Ratliff M. D. , Clodfelter C. L.
Published: December 2007

Environmental Management Plans (EMPs), in addition to being good business practice, are often required by lending institutions for certain major oil and gas exploration and production projects around the world. Lending institutions requiring EMPs include the World Bank/International Finance Corporation (IFC), the Overseas Private Investment Corporation (OPIC), the Export Import Bank of the United States (Ex-Im Bank) and others.

EMPs are more than documents detailing the procedures to be used for the protection of human health and the environment. The plans will have to be implemented in the field. Therefore, effective development of these plans requires a thorough understanding of the project, which is obtained by close interaction between the various project planning groups and the EMP development team; intimate knowledge of the project environment; and familiarity with the resources available. This paper summarizes and shares experiences associated with the development and implementation of EMPs.
In-Depth Investigation of the Validity of the Archie Equation in Carbonate Rocks
Authors: Ara Talia Shamsi , Talabani Soran , Vaziri H. H. , Islam M. R.
Published: December 2007

Archie found an empirical equation for consolidated sandstones relating several formation parameters, such as, porosity and water saturation. Despite its common use by petroleum engineers, Archie equation is not easy to apply to carbonate rocks because formation parameters (a, m, n) are functions of changes in the pore geometry, clay content, tortuosity of the pores, as well as formation pressure. The other important issue that Archie equation fails to address is the fluid critical point for the multi-component state in which different phases co-exist. This being the case for light oil and condensate reservoirs, the straightforward application of the Archie equation in carbonate rocks has severe limitations. The Archie equation is valid only when the rock is strongly water wet and clay free, which is not the case in carbonate rocks. There is no linear or direct correlation between resistivity index (IR) and formation water saturation in the carbonate rocks. Therefore, the Archie equation cannot be generalized over the entire carbonate reservoir.

In this paper, a series of experiments is performed in order to derive the correct form of the Archie Equation that can be applied to carbonate rocks. The parameter a is further split to account for the composition, pore geometry and formation pressure. By separating these parameters, it is possible to find more precise correlation with formation resistivity and formation water saturation for carbonate reservoirs. Also derived are the correlations between resistivity and the composition of the carbonate rock as well as formation pressure. Finally, an equation is proposed for taking into account changes due to the presence of critical fluids. The generalized equation can then be applied to any fluid in a carbonate formation with varied geometry and clay content.
Codell Restimulations Evolve to 200% Rate of Return
Authors: Emrich C. , Shaw D. , Reasoner S. , Ponto D.
Published: December 2007

The Codell formation is a low permeability, clay rich, late Cretaceous age sandstone within the Wattenberg field of the DJ Basin. Since 1997 over 1500 Codell wells have been restimulated. Results on the past 200 refractured Codell wells using a reduced CMG polymer fluid system have yielded incremental monthly production results in excess of 1900 BOE/well or approximately 80% of the original initial production. Success of this program is believed to be the combination of stringent well selection criteria, high fluid quality control guidelines and effective operational field practices. It is believed that due to this recent success in restimulating the Codell, over 4000 additional wells within the DJ Basin may be restimulated with economic benefits.

This paper will discuss completion history of the Codell formation and how criteria from candidate selection to fluid quality may impact the success of such a program.
Sampling Volatile Oil Wells
Authors: El-Banbi Ahmed H. , McCain William D.
Published: December 2007

Recombined surface samples are usually used for volatile oil laboratory fluid property studies. A procedure for stabilizing and surface sampling of volatile oil wells is currently used in the industry. However, no investigation of the quality of the samples resulting from this procedure has ever been published.

Typically, during surface sampling, bottom-hole flowing pressure is less than the bubblepoint pressure of the original reservoir oil. This causes gas to form in a cylinder of the reservoir around the wellbore. Understanding the dynamics of this cylinder of gas saturation is critical to obtaining a recombined surface sample representative of original reservoir oil. It is possible to obtain a representative sample if this cylinder is stable.

This paper presents the results of a study of the sampling procedure. The effects of production rate prior to and during the sampling process were quantified using radial compositional simulation. The buildup and stability of the ring of gas saturation were examined.

Guidelines for sampling volatile oil wells is presented. It is based on comparisons of the compositions of recombined surface samples with the compositions of original reservoir oils for various producing schemes. These guideline are expected to give the best chance of obtaining a representative sample from a volatile oil well.
Factors Affecting the Performance of Crude Oil Wax-Control Additives
Authors: Manka John S. , Ziegler Kim L.
Published: December 2007

Crude oil producers have used pour point depressants with great success for several decades. However, chemical wax control packages can be plagued by crude oil specificity, large package treat rates, and waxy components that can be hard to apply.

This paper discusses what factors affect the performance of crude oil wax control additives and what contributes to crude oil specificity. This study investigated the effects of the wax control additives' polymer backbone, pendant chains, and molecular weight on cold flow performance. The impact of the solvents used, the extent of the packages' dilution and the effect of proper additive dosing is addressed.
Combination of Straight Hole Drilling Device, Team Philosophy and Novel Commercial Arrangement Improves Drilling Performance in Tectonically Active Region
Authors: Barnes Michael , Vargas Carlos , Rueda Fernando , Garoby Juan , Pacione Mario , Huppertz Albert
Published: December 2007

Drilling through the complex overthrust geology associated with the Andes foothills of Northern Argentina and Bolivia presents a number of distinctive challenges. Formations in the upper hole sections (22" and 16") are typically hard, abrasive and prone to loss circulation. Historically, these intervals are particularly problematic and are responsible for major problems such as low penetration rates, hole deviation and frequent drill string failures.

While planning a well in this area, a detailed analysis of drilling performance, mud logging and wireline data from offset wells was conducted. This analysis helped identify potential problems and led the operator to set objectives for the upper hole sections of achieving the highest penetration rate possible while maintaining a near-vertical wellbore.

A strategy was developed to address the anticipated challenges. The plan had three main components including the application of a Straight Hole Drilling Device (SDD). The contract for its use was a novel combination of lump sum and incentive payment that effectively aligned the commercial objectives of the service company and the operator. Finally, the operator implemented a philosophy of teamwork that challenged all personnel involved in the well to identify the best drilling performance achievable with current technology and also feel committed to deliver a significant performance improvement.

The 12-1/4" hole section was drilled to 4700 meters (m), in only 161 days, 30 days less than the best-offset performance and 49 days less than the regional average. The 9-7/8" production liner was successfully run and cemented at this depth. Wellbore quality was also significantly better than in previous wells as shown by comparing wellbore displacement at 2300m, less than 20m with use of the SDD tool as compared to almost 150m in the closest offset. This displacement was achieved with lower average dogleg severity, which contributed to reaching the 9-7/8" casing point without any drill string failures or washouts. These achievements, along with the fact that no accidents were incurred from spud to total depth (TD), has established the new "best in class" benchmark for drilling operations in the area.

This paper describes the application of this innovative technology in addition to the drilling and novel contracting practices. The authors will outline these agreements and their advantages then highlight opportunities for further improvement.