bluuebunny/crossref_metadata_2025 huggingface dataset:
Continuous Improvement in the Design and Execution of Multilateral Projects in the Greater Ekofisk Area
Authors: Berg J. R. , Liland G.
Published: December 2007

Since 1996, Phillips Petroleum Company Norway has drilled and completed 3 bi-lateral production wells in mature chalk fields offshore Norway. There have been technical challenges all the way, but lessons learned have been captured from well to well in a very effective and constructive manner resulting in both technical and commercial success.

Technical challenges were overcome by employing: - A step-by-step approach, going from an open hole lateral to a fully cased, cemented and washed over junction (level 2 junction up to a level 4).A win-win partnering concept with contractors in a Well Construction Team (WCT) relationship;Extensive reservoir studies and modelling to assist in candidate well selection process.Refinements in drilling, completion and stimulation design and practices.Extensive off-site testing of new components and equipment prior to deployment.

A number of world's "firsts" have been achieved during this campaign, including: - Development of a liner hanger system which allows rotation, while preserving the pre-milled, casing exit window orientation.Development of a high-pressure completion window for selective stimulation of lateral and main well branches.Development of removable sleeves for highpressure stimulation which protect the junction during mainbore and lateral stimulation.Pre-milled casing exit windows with pressure integrity, reducing debris problems.

This paper describes the technical innovation and approach employed by the members of Phillip Norway WCT in realization of the multilateral projects. Results from PLTs will be given to document the contribution from the lateral branch in the three wells and a comparison to other standard horizontal wells from the same platform will be presented. Well schematics with depths and casing program will be given to support the technical discussion carried out in the paper. The lessons learned during this multilateral well development campaign have general application to mature fields in other areas of the world.
Burst and Collapse of a Sealed Multilateral Junction: Numerical Simulations
Authors: Bayfield Matt , Fisher Simon , Ring Lev
Published: December 2007

Multilateral well technology has progressed during the 1990s. Much effort is now concentrated on the development of a multilateral system where both a mechanical and a pressure seal are provided throughout by the well casing itself. Such a system would extend the application of multilaterals to a number of new environments (including higher pressure applications) and could also supersede many existing multilateral systems.

This paper describes finite element analysis undertaken to assess the effects of internal and external pressure on a sealed multilateral junction. The studies consider a junction formed between a 9.625 inch mainbore and a 7 inch lateral. Results suggest that an unreinforced junction with lateral inclined at 2.5 degrees to the mainbore would burst at 8 to 16 per cent of the mainbore casing strength and collapse at 8 to 28 per cent. Increasing the angle between mainbore and lateral to 5 degrees gives only a limited increase in strength.

Subsequent finite element simulations were then performed to suggest alternative methods for improving burst and collapse strengths. Findings indicate that values can approach standard oilfield tubular strengths if steel reinforcement is provided at the junction. A significant increase in burst strength is also predicted if the junction can be firmly cemented. The extent of this increase is highly dependent on both the quality of the cementing and the cement material properties. Benefits of cement under external pressure are generally limited due to failure of the cement.
National Health, Wealth, and Energy Use
Authors: Skov Arlie M.
Published: December 2007

There is great disparity in the distribution of wealth among nations of the world. National well-being, as measured by commonly accepted indicators such as infant mortality, child malnutrition, life expectancy, and literacy rates correlate well with national wealth, which in turn correlates well with energy consumption. Developed industrial nations rank high in national well-being, but on a per capita basis, own a disproportionate share of world wealth, and consume a disproportionate share of the world’s energy. Economic growth correlates well with growth of energy consumption in both rich and poor nations, and conversely, reductions in energy consumption correlate with economic decline. When energy consumption is expressed as a function of GNP instead of a per capita basis, developed nations are more efficient in use of energy than poorer ones.

Fossil fuels furnish 90% of the worlds energy (oil and gas supply 63%), and their use has grown by 14% over the last decade (oil and gas use is up 19%). Long range concerns about depleting resources of fossil fuels, and more immediate concerns about increases in atmospheric carbon dioxide produced by their combustion and the postulated ill effects of global warming, weigh against continued increase in use of fossil fuels and favor alternative energy sources. Examination of alternatives suggests that none, other than possibly nuclear and hydropower, both in environmental and political disfavor, offer hope for supplying more than a fraction of demand. Hence either natural limits on use of fossil fuels set by depleting resources, or artificial limits, in an effort to control carbon dioxide emissions as tentatively agreed to in Kyoto and Buenos Aires, stand in stark contrast to the need for more energy consumption to improve the economic development of all nations and particularly the poorer ones.

This paper explores these relationships, and identifies some of the hard choices which lie ahead, and will inevitably impact the use of oil and gas.
Disaggregated Remaining Reserves to Annual Production Ratios
Authors: Lohrenz J. , Williams C. W.
Published: December 2007

One frequently sees ratios - often abbreviated as R/P’s - of the remaining oil and gas reserves to the annual production for a specified producing sector, geographical subdivision, nation, or even the world. Inferences of the remaining "life" of the producing sector treated are then drawn from these R/P’s. These inferences are, however, highly problematic. The reason is that the annual production in the R/P’s is an aggregation of production drawn from reserves added to an inventory in prior history, usually over many years, of the producing sector. In any year, some production likely comes from reserves found when the producing sector was "discovered", some from recent additions to the producing sector’s inventory of reserves, and the rest from reserve additions between those two extremes.

A more meaningful planning tool to assess the future of a producing sector would be a disaggregated R/P unlike the usual aggregated R/P. A disaggregated R/P is a ratio of the new reserves added in a year in a producing sector to the start-of-a-year annual production rate from the new reserves added in each year. Thus, disaggregated R/P’s mirror the choices made regarding how proportionately fast or slow rates of production are developed for each new reserves addition in the history of a producing sector.

Here we invent and use a mathematical model to deduce disaggregated, as opposed to aggregated, R/P’s. We show how disaggregated R/P’s can be interpreted. But, no doubt, the most important showing is the coincidental diagnosis that conventional aggregated R/P’s as predictors have unavoidable afflictions that are, hopefully, terminal.
Economics and Resource Uncertainty: The 1002 Area of the Arctic National Wildlife Refuge
Authors: Attanasi E. D. , Schuenemeyer J. H.
Published: December 2007

The importance of properly characterizing undiscovered oil accumulation size distributions is demonstrated in the context of the recent US Geological Survey’s regional play assessment of the 1002 Area of the Arctic National Wildlife Refuge. The geologic and economic assessments are reviewed. The sensitivity analysis shows that parameters that affect the perceived undiscovered accumulation size distribution exert a dominant influence on estimates of economically recoverable oil.
Discovering Real Options in Oilfield Exploration and Development
Authors: Claeys Justin , Walkup Gardner
Published: December 2007

Techniques from the burgeoning area of real options are helping petroleum companies better value and manage their important assets. The real options perspective holds that typical discounted cash flow (DCF) techniques (including typical decision analysis or Monte-Carlo simulation) capture only part of an asset’s value; significant value also derives from the management options inherent in the asset. For example, owning an offshore lease not only gives the owner the right to develop the field, it also gives the owner the implicit option to build oversize facilities to process oil from nearby fields. This option may give the lease additional value. The question remains, however, how does one determine all of the real options embedded in an asset? What are the management flexibilities that give rise to real option value in an asset?

This paper will discuss a series of practical framing techniques that uncover the managerial flexibility and learning that are the hallmarks of real options. The techniques are fundamentally creative, rather than analytic, and focus on the entire value chain associated with the asset. By focusing on the future, the goal of the framing is to produce the set of key dynamic asset management decisions that must be made over time, and the evolving uncertainties that influence those decisions. Proper structuring of these decisions and uncertainties establishes a blueprint for calculating the value of the asset, providing a key advantage over typical valuation methods such as DCF or decision analysis. We will present examples from oil and gas projects that will illustrate how multi-disciplinary teams have used these techniques to uncover real options that contributed significant value to petroleum assets.
Valuation of International Oil and Gas Properties
Authors: Gustavson J. B.
Published: December 2007

The valuation of international concessions, prospects and producing fields varies greatly from country to country because of differences in fiscal and political regimes. The valuation of such properties must therefore include quantified adjustments for these differences in the light of comparative modes of sale of other international properties. The market for acquisitions and divestitures works by applying such adjustments also to the values derived for domestic analogues with comparable geological, engineering and economic risks.

This paper discusses the primary types of fiscal regimes found around the world, namely licenses with royalties and taxes, association agreements and production sharing contracts. Discounted cash flow models are shown readily applicable to proved reserves.

A review of a recent market transaction is presented to demonstrate these effects. Political risk in the international market is shown to be additive.
Indonesia-Predictability of Discontinuous Change
Authors: Proehl Thomas Strenger
Published: December 2007

Recent discontinuous political change in Indonesia has disrupted exploration and production operations of overseas investors. Disruption raises issues of uncertainty, risk, and pre-dictability. Political risk factors are calculated from economic and financial data. Background political risk in Indonesia is on the order of 15% and crisis political risk is on the order of 40%. The approach to political risk presented herein is consistent with the Neoclassical Liberal economic ideology that economics should determine politics.
Evaluation Issues Created by Technology Advances
Authors: Caldwell Robert H. , Heather David I.
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Hydrocarbon Economics and Evaluation Symposium held in Dallas, Texas, 20-23 March 1999.
Optimized Reservoir Development Using High Angle Wells, El Furrial Field, Venezuela
Authors: Smith Richard W. , Colmenares Rodolfo , Rosas Eulalio , Echeverria Isaura
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Hydrocarbon Economics and Evaluation Symposium held in Dallas, Texas, 20-23 March 1999.
A Proposed Standard Economic and Production Data Conversion File
Authors: Banks Richard B.
Published: December 2007

Although there are many programs, e.g., ARIES, OGRE, PEEP, PEP, FEGS, etc., etc., all of them use essentially the same data, e.g., economic and demographic parameters, plus historical oil, gas, water and P/Z data. A standard file for these data would facilitate the exchange of evaluation data among oil and gas companies, banks and consultants.
Risk Management for the Development of an Offshore Prospect
Authors: Fassihi M. R. , Blinten J. S. , Riis T.
Published: December 2007

Traditionally, deterministic evaluation of geologic prospects has been used to assess their economic potential. In this paper, a probabilistic method (Monte Carlo Simulation) is described for evaluation of an offshore prospect in the Former Soviet Union. In this technique, both the technical uncertainties (risks) and the variability of the fiscal terms were taken into account. Specifically, the uncertainties in the following parameters were included in our evaluation: Geologic (trap, seal, etc.), Reservoir (size, net pay, well rates, development pattern), Oil (gravity and GOR), Drilling (depth, radius of departure, fixed and variable costs), Platforms (numbers, construction time and cost), Gathering and Export Lines (size, costs), Operating Costs (fixed and variable), Capital Costs (cost index), Project (startup), Oil price, Tariff, Royalty, Cost Recovery, Profit Oil Split and Taxes. Then, the impact of the technical uncertainty on the project economics was compared with the uncertainty in the commercial terms. It was found that technical risks have more impact on project viability than the commercial risks.
Geochemistry in a Reservoir and Production Perspective
Authors: Huc A. -Y. , Carpentier B. , Guéhénneux G. , Magnier C.
Published: December 2007

Reservoir geochemistry has proved to be a valuable approach to constrain reservoir model and predict, or evaluate, potential production problems at an early stage in field development. The now classical reservoir geochemistry methodology is based on the interpretation of compositional variations detected in oil or in soluble bitumen from rock reservoir including gross composition and molecular distribution1,2.

These variations are usually related to long term geological processes (biodegradation, water-washing, gas solubilization, thermal sulfate reduction, and thermodynamic disequilibrium)3 which alter the original oil composition inherited from the source-rock. In the presence of efficient permeability barriers which prevent homogenization of the fluids by diffusion processes, the compositional variations can be eventually preserved over geological time.

Additionally, by the possibility of combining molecular information on test fluid samples and reservoir rock organic content, reservoir geochemistry can lead to a better evaluation of the reservoir fluid stability and detection of internal reservoir heterogeneity such as bitumen rich levels or pyrobitumen occurrence4–5.

Because such molecular information is available from the first obtained test oil or core samples, the occurrence of difference in fluid compositions across a field can be detected in advance of any production. Such information can be incorporated into the appraisal of the reservoir communicability and taken into account in the very first development scheme. Additionally, molecular fingerprints from production fluids can be used to calculate the relative contribution of individual reservoir in case of multi-reservoir single completion1 or oil mud contamination.

In parallel to this pragmatic methodology, a new reservoir organic geochemistry approach is emerging. The objective is to integrate the reservoir fluid in the geological dimension of the petroleum system. This is done through the understanding, the formalization and the modeling of the different geological processes which alter the original composition of the fluid. The aim is to calculate the effect, at the molecular level, of the mechanisms potentially responsible for the modifification of the fluid composition (thermodynamic equilibrium, thermal cracking, water-washing and biodegradation), in the context of the geological environment. Using these simulations, it becomes possible to identify the process(es) which is (are) responsible for the recognized fluid composition and eventual heterogeneity. In this respect, reservoir geochemistry becomes predictive in term of fluid distribution at the reservoir and regional scale.
New Instrumentation and Methods for Production Logging in Multiphase Horizontal Wells
Authors: Chace David , Trcka Darryl , Georgi Dan , Wang Jianrong , Atlas Baker , Bousché Olaf , van der Spek Alex , al Nasser Hassan
Published: December 2007

New hardware and interpretation methods are introduced that are designed specifically for production logging and inflow profiling in multiphase horizontal or deviated wells. The new method is intended to allow the measurement of three phase flow rates, water cut, and gas volume fraction in any flow regime. The new production logging instrumentation utilizes arrays of capacitance sensors to make across-the-borehole measurements of liquid level, holdup, and phase velocities while simultaneously making average borehole measurements of pressure, temperature, diameter and noise. Newly developed downhole flow modeling software helps pre-job planning and post-job evaluation of data consistency. Flow loop data for 500 downhole flow conditions representative of two and three-phase flow situations in a near-horizontal well are discussed. Log examples illustrate the accurate measurement of multiphase inflow profiles.
The Role of Sequential Welltesting in Improving Oil Recovery from a Closed Sand Lens
Authors: Zubari H. K. , Abdulwahab A. E.
Published: December 2007

Being a principal reservoir engineering tool, welltesting can yield very important information that can be integrated into models generated from other data sources to form more reliable models. It has been observed that welltests can be exceptionally useful when conducted in closed systems due to the significance of information that can be extracted with regard to boundaries and limits in addition to the other routinely calculated parameters; permeability and skin at one point in time. However, the concept of a sequence of welltests on the same well has been found even more important in improving the oil recovery from closed sandstone lenses in the Bahrain field. Conducted on a specific well situated within a sand lens, sequential welltesting yielded valuable information that assisted in understanding the drive mechanism and the deteriorating reservoir parameters, permeability and skin. Such method was found crucial in improving the recovery from the sand lens from a reservoir as well as single well treatment perspective. In this paper an example of how such technique aided in improving the oil recovery from a small sand lens is presented.
A New Thermodynamic-Hydrodynamic Model for Prediction of Downhole Corrosion in Oil Wells Based on Multiphase Flow Simulation
Authors: Al Hattab Mohammed I.
Published: December 2007

The findings of one downhole corrosion study for one oil field, to envisage reasons of downhole corrosion failures, and to recommend corrosion control procedures standing on an economical feasibility study are presented. The prevalent corrosion mechanisms are erosion corrosion due to excessive multiphase flow velocity of the produced fluids, under slug / transitional to annular flow regime, impingement corrosion in tubings at locations where flow changes direction, carbon dioxide sweet localized pitting corrosion (mesa), and ringworm corrosion at the upset of the tubings. Results of assessment models reflected a moderate corrosivity, that would not alone cause such severe corrosion failures, unless augmented by other influential factors as the hydrodynamics of production, and the geometry of the well. This study has developed one new realistic downhole corrosion predictive model to assess risks of downhole corrosion based on the correlation of the thermodynamic production conditions, and the chemical properties of the produced fluids to both of the well geometry, and the hydrodynamic production conditions as obtained by multiphase flow simulation of the wells. The model was verified through comparison to the results of the corrosion caliper surveys in same wells. The study recommended both of the long and short term corrosion mitigation methods and procedures to control downhole corrosion in this field based on the production optimization, sand control, and the establishment of effective corrosion monitoring, inspection and visual inspection programs.
Design of Action Plan and Monitoring Program: Secondary and Tertiary Gas Injection Pilots in a Limestone Reservoir
Authors: Al Hendi Ahmed , Boyd Douglas , Al-Riyami Ahmed
Published: December 2007

This paper documents the design issues and considerations of a miscible gas flood monitoring program planned in 1999. The objective of the monitoring program is to assess the efficiency of gas injection as a viable means to increasing oil recovery.

Based on simulation findings, it was decided to carry out three pilots; two secondary and one tertiary miscible gas injection in three sub-reservoirs.

The pilots were designed to provide information for a future Full-Field Development Plan (FFDP). Intensive data gathering and monitoring is planned to: 1) diagnose and rectify unforeseen events early in the life of the project, and 2) evaluate each individual pilot's performance. Monitoring is planned through the pilot's wells, nearby wells and two new dedicated observation wells.
Utilization of Associated Produced Gas to Improve Oil Recovery
Authors: Dehghani Kaveh , Ehrlich R.
Published: December 2007

Associated gas produced from oil fields in remote locations are costly to transport to market and if not utilized has been typically flared. Utilization of associated gas may justify some improved oil recovery processes (IOR), which would not be economic, if gas had to be purchased at world price. These IOR projects look especially more attractive if the available gas would otherwise be flared.

Gas re-injection for pressure maintenance, and injection of gas enriched with LPG's at high pressures for miscible flood are among the practiced gas IOR processes. These methods are best applied to certain geologic settings, and operational parameters. Utilizing the associated produced gas as fuel to generate steam for IOR is an alternative method.

In this paper, the overall criteria for applications of miscible gas floods and light oil steamflooding are compared and feasibility of steam injection process as a gas utilizing IOR method is examined. Application of steamflooding to three light oil reservoirs with different geologic settings is evaluated. These were a waterflooded vuggy dolomite, a deltaic sandstone structural trap with a gas cap, and a waterflooded deltaic sandstone. Optimization of steam injection to take advantage of individual reservoir characteristics is demonstrated.

Steam injection process is also qualitatively compared with other stranded gas utilization methods such as liquefied natural gas (LNG), and chemical conversion of gas to liquid. The results show that light oil steamflood projects can be designed to take advantage of post-secondary residual oil saturation distribution in a considerably different fashion than conventional heavy oil steamfloods. The results also show that light oil steamflood when applicable is a potential for utilizing the remote associated gas.
Scale Removal in Khuff Gas Wells
Authors: Mirza Mohamed S. , Prasad Vineet
Published: December 2007

The gas produced from Khuff wells in Bahrain field have exhibited severe down hole scaling problems. The scale deposits mainly consist of iron carbonate and iron sulfide. The Khuff gas contains about 6.5 % carbon dioxide (CO2) and between 500 to 2000 parts per million hydrogen sulfide (H2S). No formation water production has been observed in any of the wells and the only water produced is condensed water vapor. The hydrocarbon condensate yield from the Khuff wells is about 6 barrels per million standard cubic feet of gas produced. Twenty four out of twenty six wells have been completed with 5" C-75 or L-80 carbon steel tubing and only two wells are completed with Nickel-Chrome corrosion resistant alloy tubing.

Downhole scale deposits have been observed in most of the wells located in the periphery of the field. Scale deposits are limited to the lower sections of tubing below 7,000' and in the production casing all the way to the perforation intervals. Reduction in well deliverabilities, restricting well bore accessibility and erosion damage to surface production facilities by produced scale particles are the main problems encountered in these wells.

Acid descaling jobs have been conducted on most of the wells suffering from scale deposits with good results. In some wells caliper survey run after descaling has revealed severe metal loss in the lower tubing joints in areas where scale has been removed. Workovers have been performed to replace tubing in wells where excessive metal loss was observed.
Production Enhancement Efforts in the SPDC-W Land District-An Integrated Team Approach
Authors: Nnabuihe Larry , Orunta Ike , Boham Don , Ukpebor Isaac
Published: December 2007

This paper presents the new approach to production enhancement adopted in the land area of SPDC-West, Nigeria. SPDC's funding difficulties in 1995 shifted the emphasis from development drilling and well completion activities to low cost enhancement of production potential in existing wells and facilities in order to maintain availability. To make the production enhancement process more effective, problem areas were identified viz: ineffective communication between field and office based staff, an incomplete well surveillance data-base for identifying enhancement candidates, lack of focus and perceived lack of resources and funding. To remedy these problems, the following initiatives were taken in 1995: four cross-functional teams were set up with Petroleum Engineering, Production Programming, Maintenance Engineering and Field Operations staff, focused on particular fields;performance was monitored on a monthly basis by the area Production Superintendent and Chief Petroleum Engineer and quarterly by the Production and PE Managers. Resource problems that could not be resolved at a lower level were also addressed at these meetings;a quality Well Surveillance Report, addressing some 600 drainage points, is produced and published quarterly, incorporating validated data.

The team structure and targets forced team members to break through the functional barriers and feel responsible for the whole process from candidate identification to field implementation. The effort yielded 31,000 bopd net oil gain in 1995 (comparable to the production of a new flowstation), with similar results in 1996 and 1997.
Effects of Permeability contrast in the Near Wellbore Flow Patterns-Comparison Between Experimental and Numerical Studies
Authors: Al-Marhoon N. O. , Carter J. N. , Grattoni C. A. , Dawe R. A.
Published: December 2007

An understanding of the factors influencing formation damage in the near wellbore area will assist the development of drilling and production methods which minimize the creating of damage, as well as improve the treatments used to remedy any damage. In this paper, we compare our experimental work of the flow through different heterogeneous media with simulation and test different parameters (permeability, miscible flow and immiscible flow) to highlight the impact upon the flow patterns and recovery. Our experimental work demonstrates particularly differences in flow and displacement behaviour between heterogeneous and homogeneous porous media. The heterogeneity under investigation is permeability contrast. In our experiments we have used visual 5-spot models packed with Ballotini glass beads. The packings have been carried out with different sized beads in selected areas to represent the heterogeneities. Our simulations have been carried out using the Eclipse numerical simulator. The experimental flow patterns resulting from the distribution of heterogeneities were successfully simulated.

Further analysis is showing how these effects can be included in the characterisation of the reservoir and improve the accuracy of the reservoir simulation. This will in turn reduce the range of uncertainty when interpreting and integrating history match, well tests and well logs.
Analytical Modelling of Cyclic Steam Stimulation Using Pseudo-Relative Permeability Function
Authors: Tamim M. , Rahman M. H.
Published: December 2007

Cyclic Steam Stimulation (CSS) process is a proven commercial oil recovery method in heavy oil reservoirs. In many of the heavier reservoirs, steam is injected under high pressure to create fractures at the wellbore. The changes in mass and heat transfer properties created by high pressure steam injection in the deformed shear failure zone around the wellbore have been shown to influence recovery mechanism. This work presents an analytical model, which considers the shear failure zone permeability in reservoir simulation by means of pseudo-relative permeability functions.

The pseudo-relative permeability functions have been successfully applied to an analytical predictive model which considers flow into a circular wellbore at the center of an elliptical drainage system. The simulated results obtained from the new model shows excellent agreement with previously reported results in Cold Lake, Alberta oil sand.
Microbial Enhanced Oil Recovery Pilot Test in Piedras Coloradas Field, Argentina
Authors: Maure M. A. , Dietrich F. L. , Diaz V. A. , Argañaraz H.
Published: December 2007

Extensive feasibility tests involving Microbial Improvement Technology were conducted with the two main productive formations in Piedras Coloradas Oilfield, Mendoza Province, Argentina. The program started March 1997 and continued during twelve non-consecutive months. Six producer wells, two of them horizontals, were under a systematic program of inoculations using hydrocarbon-degrading anaerobic-facultative microorganisms. A complete set of rheology parameters, specific geochemical fingerprints and biomarkers comparison was used to evaluate pre- and post-trial compositional alterations in produced fluids.

Project performance in terms of fractional flow evolution was correlated with well completion configuration and reservoir petrophysics by the use of parametric models and compared on a well-by-well basis with corresponding decline and complementary baselines. Incremental Oil averages 66% over baseline with minimum values of 28.5% and maximum above 110%. Results are consistent and show a clear correlation between treatment design modifications and water cut reduction. This correlation proves that Microbial Enhanced Oil Recovery methods are controllable and predictable if team integration and proper engineering methods are observed during pilot design and well monitoring stages.

Cost per Incremental Barrel (CIB) was 5.1 $/barrel during pilot stage. On MEOR Expanded scales, this value is forecast to decrease to below 2 $/barrel. The project demonstrates that this technology is cost effective, easy to implement and complies very well with local environmental regulations and biosafety issues.

This pilot program is the first part of an integral mid-term strategy to use biotechnology in paraffinic oil bearing reservoirs. Further evaluations in course will be covering microbial influence mechanisms on waterflooding methods.
Mechanistic Study of Alternative Gas Injection Processes for Enhanced Oil Recovery in the Los Jabillos (Cretaceous) Reservoir, Furrial Field, Norte Monagas, Venezuela
Authors: Todd M. R. , Claridge E. L. , Almeida J. , Alvarez R. , Echeverria I.
Published: December 2007

A numerical simulation study of enhanced oil recovery alternatives has been conducted for a reservoir characterized by a thick oil column having varying crude oil composition and associated transport properties with depth. The high asphaltene content of the crude, together with indication of plugging if precipitation is allowed to occur in the reservoir, has forced the maintenance of pressure by injection. This study examines the efficacy of alternative injection processes. Described is the procedure used to represent a miscible-immiscible transition, as anticipated to occur between injectors and producers, in a pseudo-miscible simulator, starting with the results of slim-tube experiments. Reservoir stratification in the representative cross-section model used for the simulations is based on Lorenz functions. The modeling work indicates significant sensitivity to both process and well configuration, with continuous gas injection predicted to recover 0.03 to 0.09 OOIP more oil than water injection, and 1:1 WAG predicted to recover 0.06 to 0.10 OOIP more oil than continuous gas injection, depending on the well configuration.
Application of Low Invasion Coring and Outcrop Studies to Reservoir Development Planning for the Villano Field
Authors: Rathmell J. J. , Atkins Laura K. , Kralik James G.
Published: December 2007

Drilling and coring of a discovery well in the Hollin sand, Villano Field in 1992 was followed by low invasion coring in a confirmation well. A large discrepancy existed between water saturation derived from the capillary pressure and well logs in the discovery well. Low invasion coring and outcrop studies were implemented to calculate oil-in-place and hydrocarbon reserves.

The field is located in environmentally sensitive rain forest. Low invasion coring with water based mud was the only feasible method for obtaining connate water saturation from core. The bromide tracer of mud filtrate indicated low invasion (<10 % pv filtrate) was found in 86% of the horizontal core plugs. Core plugging and preservation were conducted in a facility established at the drilling base camp, 30 minutes by helicopter from the rig.

These plugs were then shipped to the USA for analysis. Core water saturation was in good agreement with capillary pressure tests. The low invasion core data indicated salinity varied from 2600 ppm chloride at water-oil contact to 36,000 ppm chloride at the top of the Hollin reservoir. This salinity gradient and native-state, Archie saturation exponent yielded log-derived water saturation equal to the low invasion core values.

Reservoir description would be critical to a development plan for the field, which would produce by aquifer influx. The size and distribution of sand bodies and shales was addressed by a detailed description of the core to determine the sedimentary sequence and quality of the productive intervals, and measurements from a Hollin sand outcrop located in the Andes Mountains to the northwest of the field.

Geostatistical methods were used for shale mapping. An objective geological model based on cores and outcrop was used to assign sand permeability, porosity and water saturation. Numerical simulation with this description and the steady state relative permeability data provided an oil rate forecast and the Plan of Development for the field.
Knowledge Communities Help to Identify Best Operating Practices
Authors: Saputelli Luigi , Ungredda Alessandro
Published: December 2007

This paper addresses state-of-the-art in knowledge management as applied to an E&P organization, lessons learned in the last decade and current challenges for adopting this philosophy. It shows the advantages in using novel knowledge management techniques, as applied in many successful and competitive companies. It promotes learning organization's philosophy, and the creation of virtual knowledge communities to identify best operating practices. Some techniques and tools are described in order to promote team effectiveness strategies and communications to leverage knowledge sharing and valur creation.
Multiple Internal Rates of Return - When to Anticipate Multiple IRRs and How to Take Advantage of Them to Perform a Better Evaluation
Authors: Rosbaco Juan A.
Published: December 2007

There are different rules to delimit or exactly determine the number of Internal Rates of Return a project may have or has. These rules show that, when the sequence of signs of the cumulative cash flow vs time function is the normal one - negative figures at the start and then only positive ones - there is only one Internal Rate of Return. There are few projects in which there are multiple intersections of cumulative cash flow with the time axis: a number of acceleration projects, complex financing investments, and a few other serial projects. However, not all of them have multiple Internal Rates of Return. The discussion presented in this paper addresses the question of how to empirically infer the existence of multiple rates, and how to use them for the benefit of the evaluation. Moreover, it demonstrates that all multiple rates have the same physical meaning, which does not vary with respect to the traditional single rate case.
A New Micro-Emulsion Polymer Gelling Agent with an External Surfactant Gellant Activator Improves Acid Fracturing
Authors: Woo G. T. , Lopez H. , Metcalf A. S. , Boles J.
Published: December 2007

Typically, the gelling agents used in crosslinked hydrochloric acid are available as polymer dispersions with a pre-blended inverting agent or gellant activator. An inverting agent increases the polymer dispersion' s viscosity initially and will further increase the polymer dispersion' s viscosity over the shelf life of the product. As a result, the polymer dispersion' s pour point and stability are adversely affected, thereby reducing the polymer dispersion' s shelf life. Additionally, the use of a nonylphenol ethoxylate, the inverting agent commonly pre-blended in polymer dispersions has been banned in the North Sea due to environmental concerns.

A new gelling system for crosslinked acid fracturing treatment has been developed. The system includes a microemulsion polymer gelling agent and a highly specific surfactant that is used as an external activator. The microemulsion polymer possesses very unique and more desirable properties such as a lower pour point and viscosity profile, a greatly enhanced dispersability, and a microscopic emulsion polymer particle.

With a lower pour point and innate viscosity profile, the gelling agent is readily pumped directly from the shipping vessels to the blending unit even in cold weather. With such a greatly enhanced dispersability, the gelling agent is readily dispersed in the hydrochloric acid without the risk of forming unhydrated masses or " fish eyes". Additionally, the microscopic emulsion particle greatly prolongs the shelf life of the gelling agent by virtually eliminating polymer settling. With the use of the special external gellant activator, the emulsion polymer could achieve 70% or more hydration within one minute. The characteristics of the gelling agent and the use of the external activator enable the gelling system capable of "continuous mix" or " on the fly" operations.

In addition, this external activator is biodegradable making it more conducive to the environment.

This paper describes the chemistry of the new gelling system, its enhanced gelling capabilities, discusses the results of lab testing leading to its development, and finally, the results of extensive field-testing.
Use of Capillary Pressure Data and Log Calculated Water Saturation for the Characterization of Dual Porosity, Dual Permeability Systems
Authors: Ozgen C. , Araujo H. , Firincioglu T.
Published: December 2007

This paper describes a simple method to divide the effective porosity values that can be calculated from log analysis into two flow media (fracture and matrix) pore volumes for use in numerical simulation models. The division of the porosity is based on the assumption that the total porosity of the system is made up from two contributing rock types or lithofacies that have distinct pore size and/or pore size distribution such that they can be represented by different capillary pressure functions. This assumption is applicable to the non-fractured as well as to the fractured systems.

When the method is used for the fractured systems, the fracture is typically represented by a zero capillary pressure value (gravity segregation). The matrix has its own laboratory measured capillary pressure curve. Based on a predetermined water-hydrocarbon contact and using the difference between the density gradients of the fluids, the capillary pressures of the two media are converted to theoretical water saturation profiles as a function of TVD. Next, at each depth point, the two extreme theoretical water saturation values are compared to the log calculated water saturation measurements. Based on a simple weighting algorithm, the contributions of the fracture and matrix media to the total porosity are calculated. The results can be upscaled to the numerical simulation grid block size or be used in geostatistical approaches.

Using the developed technique, we have built simulation models for two different reservoirs. One of the models represents a fractured system, while the other represents a non-fractured system with two distinct rock types. For the non-fractured reservoir, the dual porosity formulation enabled us to accurately upscale the capillary pressure functions by default. The approach and the results of the numerical models are presented in the body of this paper.
Velocity Dispersion as a Tool for Reservoir Imaging
Authors: Sidorovskaia Natalia A. , Lockard Emmitt S.
Published: December 2007

A comparison of the seismic velocities estimated from actual seismic data and well logs shows apparent discrepancies for the certain frequency ranges. The difference is related to the presence of the propagation velocity dispersion typically ignored in seismic signal processing as the second order effect In addition, neglecting the effects of velocity dispersion in seismic imaging algorithms reduces the resolution in mapping the reservoir properties. Several theoretical models relating seismic data and their dispersive properties to important reservoir characteristics, such as porosity, permeability, fluid saturation, etc., are discussed. Velocity dispersion and signal attenuation in rocks with fluids are mostly affected by two mechanisms of the fluid-solid interactions, the Biot mechanism and the so-called "squirt flow" mechanism. The Biot mechanism is the more conventional one and it occurs at the macroscale level, whereas the "squirt flow" mechanism describes fluid flow at the pore scale level. It is considered how one can relate velocity dispersion and attenuation to measurable rock and fluid properties by coupling two mechanisms. New aspects of modeling attenuation and dispersion effects in partially saturated fluid based on statistical approach to scattering from aggregates of gaseous bubbles is also introduced.

The results indicate the first step in modeling complex reservoir properties from broadband interwell and surface seismic data. It can be particularly applied to the extraction of permeability anisotropy from attenuation and dispersion data to image the fluid flow in a reservoir. The separation of the elastic scattering component of the velocity dispersion could be useful for the prediction of depositional environments. The task to predict the dispersive properties of the reservoir away from the well control using interwell and surface seismic information can be also accomplished.
Integrated Reservoir Characterization Incorporating Horizontal Well Data. Bare Field (Seismic 3D Area) Orinoco Oil Belt. Venezuela.
Authors: Granado A. , Rojas B. , Fuenmayor M. , Calderon P. , Ramos C. , Nalsen M.
Published: December 2007

This paper summarizes the results of an integrated reservoir characterization study, and the volumetric analysis of a section of the stratigraphic column of the Bare field, Hamaca Norte, Orinoco Oil Belt, in eastern Venezuela (fig.1). Also development plans for the studied area, containing an OOIP of approximately 9.5 MMMSTB of heavy/extraheavy (8–18 API) crude, are provided.

The reservoir characterization study was made by an integrated interdisciplinary team of Geoscience professionals, facilitating the identification of opportunities for growth in hydrocarbon reserves in the Bare area. The process was initiated with the determination of the reservoir internal architectures, through the description, correlation and mapping of the geological data. The application of high-resolution sequence stratigraphy was essential for the determination of the reservoir architectures. Next, after all the production and reservoir data were incorporated and integrated, a reservoir model was generated for dynamic simulation and for the development of potentially recoverable reserves. 32 possible locations for horizontal wells were identified and ranked according to productivity and profitability.

The geological model was corroborated through the drilling of 8 new horizontal wells, during 1997–98, minimizing the geological uncertainties of the area. The number of pilot holes was reduced, and navigational difficulties, during the drilling of the horizontal section, were surmounted. This has resulted in a 25 % increment in the quality and in the effective horizontal length sections of the wells. Initial well production rates are between 800 and 1400 BOPD, an average of 200 additional BOPD as compared to wells drilled prior to this study. Additionally, the study defined the optimum distribution and location of production facilities and infrastructure.
Application of Surface Modification Agent in Wells with High Flow Rates
Authors: Weaver Jim D. , Baker John D. , Woolverton Sean , Parker Mark A.
Published: December 2007

This paper describes the laboratory development and field evaluation of a new enhanced proppant surface-modification agent (ESMA) that increases fracture conductivity, dramatically reducing proppant backproduction during the initial high flow-rate well cleanup after fracture-stimulation treatments. The conventional surface-modification agent (SMA), which has been used extensively, enhances fracture conductivity by reducing proppant flowback in wells with moderate flowback conditions. ESMA extends the use of proppant surface-modification technology to wells with potentially harsh flowback conditions.

SMA applications allow proppant packs to withstand three-to five-fold the critical flow velocity required to erode a proppant pack. When a crosslinker additive is incorporated, forming ESMA, this range extends 10- to 20-fold. Laboratory tests indicate that ESMA will demonstrate the same improvements expected from SMA in vertical distribution of proppant because of hindered settling. Typically, these materials provide a 15 to 30% increase in proppant-pack porosity. With both SMA and ESMA, fines resulting from proppant crushing and formation fracturing adhered to the treated pack and did not migrate or block pore throats. Fracture-fluid cleanup significantly improved when proppant was treated with either additive.

Several successful field tests were performed with ESMA, including fracture stimulation with limited entry in the Mesa Verde, where proppant packs were subjected to initial flow rates as high as 45 bbl/hr. In all of these tests, no proppant flowback was observed, and well productivity was enhanced. The paper includes designs and results for some of these field tests.