bluuebunny/crossref_metadata_2025 huggingface dataset:
Risk Evaluation For Recompletion and Sidetrack Developments in Oil Fields
Authors: Lerche I. , Mudford B.
Published: December 2007

There are two very similar problems in development of an oil field related to recompletion or to sidetrack of an existing producing well to an undeveloped horizon or fault block. In both cases, one has drilled and is producing an horizon, and one also knows from exploration drilling that a shallower horizon, or an adjacent fault block is present that is oilbearing. As the first horizon progressively yields its recoverable reserves, corporate attention shifts to the question of producing the remaining horizon in order to bolster cash flow.

There is some risk that the recompletion or sidetrack will fail, so there is a chance that one will stop production in the currently producing zone and also fail to get production from the new zone. The economic question of interest concerns the expectation of total recoverable oil and the likely cash flow that could accrue. In other words, the economic potential of the recompletion or sidetrack must be tied to the chances of success and failure. The economic worth of a sidetrack or recompletion are frequently evaluated by using deterministic decision tree analyses to determine the expected monetary value (EMV) generated by the new expenditure. This technique can be extended in several ways as is shown here. Firstly, with deterministic inputs into the decision tree, one can estimate the uncertainty in the EMV, and the probability of exceeding some minimum value. Secondly, with uncertainty in the inputs, such as cost and production, one can calculate the full net present value distribution, both approximately and using Monte Carlo simulation. The second case provides a realistic view of the uncertainty in the economic potential of the recompletion or sidetrack, given inherent uncertainties in the project. Some examples are presented to illustrate these points succinctly and sharply.
An Investigation of Risk and Probability in a Portfolio Management Context
Authors: DuBois James R.
Published: December 2007

The oil and gas industry often makes investment decisions based on expected value numbers. This can be quite misleading, particularly when programs are small and time frames for evaluation are short. Expected value numbers must be tempered with the knowledge of the probabilities of meeting target values on an annual basis to give a true picture of future expectations.

Most portfolio models use some sort of risk function in building models, so it is often assumed that, by choosing a low risk portfolio, we are choosing a portfolio with a high probability of meeting our metric targets. This is not usually the case. Risk and probability are quite different concepts. In fact, as we show with examples, a low risk portfolio will often have poorer probabilities of meeting some metric targets than will a high-risk portfolio.

At present, portfolio models generally do not use probabilities or confidence levels in the formulation of the portfolios on the efficient frontier, although these probabilities can be calculated after the fact. Models are being developed that will soon be able to use these confidence levels in forming portfolios. In the mean time, there are a few ways to influence probabilities within a portfolio model, and one of these is illustrated. The methods of influencing probabilities will always be part of the portfolio manager's tool kit and will provide the foundation for the next generation portfolio analysis.
Health, Safety and Environmental Data Management of Chemicals in a Global Service Company
Authors: Killaars Janine , Solvberg Liv , Webb Alfred
Published: December 2007

Service companies that work in different countries in all parts of the world, have a significant challenge with respect to the preparation and quality assurance of HSE (Health, Safety and Environmental) documentation for chemicals. They have to comply with the applicable regional and country specific legislation, customers’ HSE standards and internal HSE standards. Besides these requirements an important issue is the different interpretation of the HSE data by authorities.

Internal HSE processes are used to obtain and evaluate compositional and HSE-information on all chemical products. Accurate compositional information is needed to assess the chemical on its HSE properties, prepare the HSE documentation and to submit the product to the authorities. The quality and consistency of this information is maintained by following the established chemical compliance system, and by maintaining close communication between HSE Chemical Compliance, Procurement and the Product Service Line.

To streamline these processes in a logical way it is crucial to have procedures and systems in place that can handle all applicable HSE information and documentation. The software must be tailor-made for the specific requirements, and easy to use and maintain, as it must be kept updated according to the continuous changes in both the product portfolio and in the different legislation.

This paper describes an approach as to how the HSE data for chemicals can be managed and what processes and systems are being used. The following topics are discussed:

Processes used to introduce new products Processes used to maintain chemical consistency Processes used to attain local chemical HSE compliance Handling of compositional and regulatory information HSE documentation requirements and procedures HOCNF (Harmonized Offshore Notification Format) management MSDS (Material Safety Datasheet) management

HOCNFs are a North-Sea requirement. This document contains the compositional and environmental data for chemicals that are used offshore in the North Sea. MSDSs are used worldwide and have different formats and labelling requirements.

Overviews of the different systems are given as well as database set-ups and how they are linked.
Multiple Controls on Petroleum Biodegradation and Impact on Oil Quality
Authors: Wenger Lloyd M. , Davis Cara L. , Isaksen Gary H.
Published: December 2007

Biodegradation of oils in nature is important in reservoirs cooler than approximately 80° C. Oils from shallower, cooler reservoirs tend to be progressively more biodegraded than those in deeper, hotter reservoirs. Increasing levels of biodegradation generally cause a decline in oil quality, diminishing the producibility and value of the oil as API gravity and distillate yields decrease; and viscosity, sulfur, asphaltene, metals, vacuum residua, and total acid number increase. For a specific hydrocarbon system (similar source type and level of maturity), general trends exist for oil quality parameters versus present-day reservoir temperature < 80° C. However, additional controls on biodegradation may have significant effects, making pre-drill prediction of oil quality difficult.

It has long been observed that fresh, oxygenated waters in contact with reservoir oil can cause extensive aerobic biodegradation. More recently it has been recognized that anaerobic sulfate-reducing and fermenting bacteria can also degrade petroleum. Highly saline formation waters may inhibit bacterial degradation and effectively shield oils from oil-quality deterioration. The timing of hydrocarbon charge(s) and the post-charge temperature history of the reservoir can have major effects on oil quality. Currently charging reservoirs may overwhelm the ability of bacteria to degrade the oil, resulting in better-than-anticipated oil quality. Fresh charge to reservoirs containing previously degraded oil will upgrade oil quality. Calibrated methods of oil quality risking, based on a detailed evaluation of reservoir charge and temperature history and local controls on biodegradation, need to be developed on a play and prospect basis.
Application of "Lab-on-a-chip" Technology to the Upstream Petroleum Industry
Authors: Mohanty Kishore K. , Saputelli Luigi A.
Published: December 2007

The success of integrated circuit chips in replacing large vacuum-tube operated computing machines has inspired biologists, chemists and engineers to study miniaturization of other devices in the last few years. Microelectromechanical (MEM) devices are being developed as miniature sensors and actuators. Biochips (DNA microchip arrays) are being developed to analyze hundreds (to thousands) of DNA fragments in parallel. "Microfluidics" and "microreaction" technology are being developed to downsize chemical and biochemical reactions and analysis. These devices consist of microns-size channels, valves, reactors and actuators etc. on silicon-like wafers and thus termed "Lab-on-a-chip". This paper reviews these developments that are primarily outside the petroleum industry. The advantage and disadvantage of this technology is discussed along with potential applications in the upstream petroleum industry. The breakthroughs needed for practical application are outlined. Miniaturization of chemical analysis can lead to new downhole equipments. It can also lead to smaller samples and faster fluid analysis.
Reservoir Conformance: Tracking Gas/Water Contacts via Capillary Shockwave Fronts
Authors: Goldsberry Fred L. , Holland Jeffrey T. , Gross William E. , Wildenstein Rudy C. , Salzman David L.
Published: December 2007

Much of the technology developed in the oil industry today is the result of cooperative engineering research efforts between operating companies with a problem and a technology developer with a potential solution. Often all parties discover the unexpected in the course of making physical measurements. In this case, the data captured showed the advancement in time of the limit singularity associated with a gas/water contact. The purpose of this paper is to share knowledge that may be useful to other operators, particularly those with permanent pressure gauge completions in oil and gas wells, or those operators who may use precision pressure gauges to monitor the flowing tubing pressure of a gas well.

The authors’ companies have engaged in joint reservoir evaluation efforts to resolve rapidly declining production behavior in gas wells. The efforts were based upon pressure transient well evaluations utilizing the capillary shock front theory to map the gas cap at the time of the test. Two examples are presented that illustrate water contact boundary progression just prior to the onset of water production in each of the wells. The joint efforts have resulted in a better understanding of how to use operational shut-ins to monitor gas/water contacts from the inception of flow to the point of water encroachment. The goals of this effort are to see the end coming and perhaps delay the end in order to maximize well production. The secondary goal is to predict the end so as to avoid unnecessary post mortem efforts to repair a well that has watered-out.

The first case is a test of a deep well in Louisiana that was being evaluated for rapidly declining pressure and flow rate. The second well was offshore in the Gulf of Mexico that was being evaluated for geology and remaining reserves. The movement of the limit contacts over time is illustrated with a sequential limit mapping presentation. A second test is presented to show an overlay of two tests performed two weeks apart, just before the well watered out.
Use of Laser Technology for the Treatment of Asphaltene Deposition in Carbonate Formation
Authors: Zekri Abdulrazag Y. , Shedid Shedid A. , Alkashef Hassan
Published: December 2007

Crude oils produced in many parts of the world contain asphaltenes. Asphaltenes plugging is a well-known cause of near-wellbore formation damage. The deposition phenomenon of asphaltene is mainly due to thermodynamic changes. Asphaltene deposition leads to production loss and requires expensive and in many times environmentally unfriendly corrective measures. This project proposes a novel technique for cleaning asphaltenes with laser energy. A laboratory laser diode modules was used to perform experiments. A two-inch column of bitumen/powdered limestone mixture was placed on top of a powdered limestone column in a flow cell, and the flow rates were measured before and after the laser treatment. The rate was correlated with permeability of this powdered limestone column in absence of bitumen. In a second series of experiments, actual consolidated limestone cores were subjected to flow of asphaltenic crude to simulate the damage process (i.e. permeability reduction). The damaged cores were subjected to laser treatments at various laser intensity and treatment time intervals.

Experiment results indicated that asphaltene get disrupted after exposure to laser energy. However, the maximum amount of cleaning was noticed after an exposure of one hour and at a higher laser intensity. The increased flow rate measured employing the powdered limestone column after treatment can be used in an oil field to disrupt, or desegregate asphaltene from the vicinity of oil production wells. However, the simultaneous pumping is required during the laser treatment to avoid the reprecipitation of the disrupted asphaltene. The laser cleaning technique appears to be disrupting the maltenes that form a continuous phase providing adhesive and ductile properties to the dispersed asphaltene. The proposed technique provides environmental friendly process and advanced technological breakthrough for treating asphaltene deposition in the petroleum industry.
MEMS-Based Corrosion and Stress Sensors for Non-Destructive Structural Evaluation
Authors: Morse J. , Laskowski B. , Wilson A. R.
Published: December 2007

A system utilizing multiple types of microsensors for monitoring corrosion, fatigue, and failure in high value structures is described. Non-destructive evaluation (NDE) techniques enabled through microelectromechanical systems (MEMS) sensor approaches allow monitoring of the occurrence and rate of corrosion under sealants coated (painted) surfaces and other inaccessible areas. Using MEMS technology it is now possible to integrate and package sensors with associated CMOS control circuitry onto a single semiconductor chip. These sensors can provide information on the presence of stress, fatigue, corrosion, and micro-crack formation in structures being monitored. This combination of data provides critical assessment of structural health, leading to predictions of failure occurring. Two types of sensor devices will be discussed, along with results from specific applications.
Study of the Effect of ASP Solution Viscoelasticity on Displacement Efficiency
Authors: Jirui Hou , Zhongchun Liu , Xiang’a Yue , Huifen Xia
Published: December 2007

In application of Alkali-surfactant-polymer flooding, people always follow after ultra low IFT and negate the effect of ASP solution viscoelasticity on displacement efficiency. For getting the ultra low IFT, ASP solutions need the high concentration of alkali, for example, the ASP flooding needs 1.2%wt NaOH in Daqing oilfield. It brings not only many new technological problems such as scale production in well bore, sticking of pump, reduction of injectivity etc, but also decrease of polymer viscoelasticity. In addition, the selectable range of surfactant for ASP flooding falls a definite limitation due to the restriction of ultra low IFT.

As to ASP flooding in the pilot area of Daqing oilfield, the analysis of ASP solution's rheology and physical simulation experiments have been carried out for studying the effect of alkali on viscoelasticity of displacing phase and the effect of viscoelasticities of ASP solution on displacement efficiency in this paper. Experiments include two types, macrodisplacements and micro-displacements. Cores have artificial heterogeneous models, natural cores and micro-models. The results show that decreasing alkali concentration increases the viscoelasticity of ASP solution, and the displacement efficiencies of ASP solution with low alkali concentration aren't less than that with high alkali concentration and ultra low IFT. At same time, the effect of ASP solution's viscoelasticity on displacement of residual oil in different diameter pores of parallel connection has been analyzed theoretically. The limit of capillary number theory has been discussed in ASP flooding. The mechanism of ASP flooding has been recognized again. The mechanism that viscoelasticity is more important than ultra low IFT as a factor of affecting displacement efficiency has been confirmed. Therefore, Decreasing the amount of alkali and weakening the demand of low IFT not only enlarges the selectable range of surfactant and decreases the costs of ASP flooding, but also solves the problem of alkali scale, and are of great importance to the further development of ASP flooding and its application.
Heat Transfer Ahead of a SAGD Steam Chamber, a Study of Thermocouple Data From Phase B of the Underground Test Facility (Dover Project)
Authors: Birrell G. E.
Published: December 2007

Phase B at the Underground Test Facility (Dover Project) is the longest running and most instrumented SAGD pattern in the world and is operated by Northstar Energy. Techniques are presented which allow for the interpretation of temperature data from the pilot to better understand the growth of a SAGD steam chamber over time. Calculating the rate and direction of steam chamber movement, the in situ thermal diffusivity and the role of conduction and convection in heat transfer provide a foundation for understanding the interaction between the SAGD recovery process and the reservoir.
Effects of Asphaltenes and Resins on Foamability of Heavy Oil
Authors: Bauget F. , Langevin D. , Lenormand R.
Published: December 2007

Because of the existence of large reserves, the production of heavy-oils is the object of increasing interest. Some heavy oil reservoirs show anomalous behavior in primary production, with rates of production better than predicted. Interpretations based on the formation of foam (or bubbles dispersion) have been proposed. However there is no evidence for foam production in reservoirs and a mechanism based only on high viscosity has also been proposed. In order to determine the real mechanism, we have studied the "foamability" of heavy oil from South America.

The experiments consist of standard measurements in foam studies: qualitative measurements (foam volume, thin film lifetime), and physical properties (volume viscosity, dynamic and static surface tension, elastic modulus). Due to the high viscosity of the crude oil, measurements were performed on solutions of resins and/or asphaltenes in toluene. Asphaltenes were extracted by the HPLC method, and resins by adsorption on silica gel. First, solutions with only asphaltenes were used with concentrations in weight from 1% to 20%. The effect of resins was then investigated using solutions with various resin and asphaltene concentrations.

The main results are:

The presence of asphaltenes enhances foamability and film lifetime, with a large variation in all measurements at around 10% asphaltene concentration. A very long characteristic time of dynamic tension and a large increase of elastic modulus were observed. Added resins have no effect on foam volume. However, the threshold in properties around 10% asphaltene concentration is no longer observed with resins.

The results can be interpreted with existing models for polymer clustering and interfacial behavior of proteins. As proteins, asphaltene molecules can reorganize themselves at the interface, leading to a long time of tension decrease and a high increase of elastic modulus. The effect of resins is analyzed by comparison with crude-water emulsion. In conclusion, with the systems we have studied, asphaltene fraction enhances significantly foam properties (foamability, single film lifetime, surface rheology) above 10% in weight. Because problematic is flow of heavy oil in porous media. Then we have also performed experiments in glass micromodel with the same fluids, but no proofs of interfacial effects were observed.
Optimization of Displacements in Porous Media Using Rate Control
Authors: Sudaryanto Bagus , Yortsos Yanis C.
Published: December 2007

In many applications involving the injection of a fluid in a porous medium to displace another, a main objective is the maximization of the displacement efficiency. For a fixed arrangement of injection and production wells, such optimization is possible by controlling the injection rate policy. This paper is an abbreviated version of Ref. [1], where we described a fundamental approach based on optimal control theory, for the simplified case when the fluids are miscible, of equal viscosity and in the absence of dispersion and gravity effects. Both homogeneous and heterogeneous porous media are considered. The optimal injection policy that maximizes the displacement efficiency at the time of arrival of the injected fluid, is of the "bang-bang" type, namely where the rates take their extreme values in the range allowed. This result applies to both homogeneous and heterogeneous media. Examples in simple geometries and for various constraints are shown. In the heterogeneous case, the effect of the permeability heterogeneity, particularly its spatial correlation structure, on diverting the flow paths, is analysed. "Bang-bang" injection remains the optimal approach, compared to constant rate, if they were both designed under the assumption that the medium was homogeneous.
Novel Well Testing Procedures Prove Successful in Dakota Formation Infill Program, San Juan Basin
Authors: Frantz J. H. , Shannon P. M. , Moody C. E. , Glaser T. , Sawyer W. K. , Williamson J. R.
Published: December 2007

Conoco implemented a novel well testing program in six infill wells to evaluate the differential pressure depletion in the Dakota formation in a portion of the San Juan Basin in Rio Arriba County, New Mexico. The field program consisted of performing pre-fracture nitrogen slug tests or pressure buildup tests. Each of the three Dakota sands were evaluated separately, and in four wells, simultaneously to estimate permeability-thickness product, skin factor, reservoir pressure, and gas in place. The novel approach allowed for all sands to be tested quickly. The infill wells were drilled on 80-acre spacing among existing 160-acre spaced Dakota wells.

The Dakota formation is a series of tight, normal-pressured sands and is one of the main productive units in the San Juan Basin. The average reservoir pressure, as indicated by these tests, ranges from 2,500 psi to 2,900 psi. The original reservoir pressure was 3,200 psi. The post-fracture in-line production rates were excellent averaging between 350 to 900 Mscf/D after two months in-line. Single- and multi-well reservoir models were developed to predict the expected longterm performance from the infill wells.

This paper highlights the novel pre-fracture well testing program including the methodology utilized by Conoco to meet the challenging testing needs present in the Dakota formation in San Juan Basin. The testing approach of using either nitrogen slug tests or simultaneous, individual zone, buildup tests can be used in most tight gas sands consisting of multiple sands.
A Successful Polymer Treatment For Water Coning Abatement in Gas Storage Reservoir
Authors: Zaitoun A. , Pichery T.
Published: December 2007

A polymer treatment has been successfully applied in a Gaz-de-France gas storage well facing excessive water production problems limiting its maximum gas flow rate. The well was located in a limestone reservoir submitted to an active bottom aquifer. To reduce the risk of well impairment while enhancing the efficiency to fight water coning, the polymer slug was injected into the half of the open interval located at the bottom of the reservoir. A study consisting of laboratory core tests and numerical simulations aimed at sizing polymer slug and concentration before performing the treatment. The level of water permeability reduction to reach was fulfilled with single polymer adsorption without the need of adding cross-linker.

After a period of two years where no significant effect on water production occurred, the well progressively improved its performances while water production remained at the same level in neighbour wells. After ten years of survey, the well, which was one of the worse of the storage, became one of the best, capable to sustain high levels of gas production with low water. The delay in well response is probably due to the high water saturation level of the reservoir surrounding the wellbore consecutive to the injection of the polymer slug. The results show that the technique, while easy to handle, gives remarkably efficient long-lasting effect.
Oil-Water Separation in Liquid-Liquid Hydrocyclones (LLHC)–Experiment and Modeling
Authors: Gomez Carlos , Caldentey Juan , Wang Shoubo , Gomez Luis , Mohan Ram , Shoham Ovadia
Published: December 2007

The liquid-liquid Hydrocyclone (LLHC) has been widely used by the Petroleum Industry for the past several decades. A large quantity of information on the LLHC available in the literature includes experimental data, computational fluid dynamic simulations and field applications. The design of LLHCs has been based in the past mainly on empirical experience. However, no simple and overall design mechanistic model has been developed to date for the LLHC. The objective of this study is to develop a mechanistic model for the de-oiling LLHCs, and test it against available and new experimental data. This model will enable the prediction of the hydrodynamic flow behavior in the LLHC, providing a design tool for LLHC field applications.

A simple mechanistic model is developed for the LLHC. The required input for the model is: LLHC geometry, fluid properties, inlet droplet size distribution and operational conditions. The model is capable of predicting the LLHC hydrodynamic flow field, namely, the axial, tangential and radial velocity distributions of the continuous-phase. The separation efficiency and migration probability are determined based on swirl intensity prediction and droplet trajectory analysis. The flow capacity, namely, the inlet-to-underflow pressure drop is predicted utilizing an energy balance analysis.

An extensive experimental program has been conducted during this study, utilizing a 2″ MQ Hydroswirl hydrocyclone. The inlet flow conditions are: total flow rates between 27 to 18 gpm, oil-cut up to 10%, median droplet size distributions from 50 to 500 ìm, and inlet pressures between 60 to 90 psia. The acquired data include the flow rate, oil-cut and droplet size distribution in the inlet and in the underflow, the reject flow rate and oil concentration in the overflow and the separation efficiency. Additional data for velocity profiles were taken from the literature, especially from the Colman and Thew (1980) study. Excellent agreement is observed between the model prediction and the experimental data with respect to both separation efficiency (average absolute relative error of 3%) and pressure drop (average absolute relative error of 1.6%).
The Development of Low-Sour Gas Reserves Utilizing Direct-Injection Liquid Hydrogen Sulphide Scavengers
Authors: Eylander J. G. R. , Holtman H. A. , Salma T. , Yuan M. , Callaway M. , Johnstone J. R.
Published: December 2007

The toxicity of hydrogen sulphide in hydrocarbon streams is well known in the industry and considerable expense and efforts are expended annually to remove hydrogen sulphide to a safe level. In large production facilities, it is generally economical to install a regenerative system for treating sour gas streams. However, during the development stages of relatively small low-sour gas fields at remote and normally unmanned locations where regenerative systems are not practical nor economical, it is necessary to treat the sour gas production with non-regenerable scavenging processes. In the development of its low-sour Zechstein gas reserves in the Coevorden field in the North-East The Netherlands, the Nederlandse Aardolie Maatschappij (a Shell operating unit, hereafter referred to as NAM) decided to adopt continuous direct-injection of liquid scavenging agents as the lowest overall cost process having the least environmental impact and the highest energy efficiency. At the inception of the project, the operating parameters controlling the scavenging efficiency using direct injection of liquid scavengers in this system were largely unknown. Consequently, numerous field trials using different chemistries and different injection mechanics had to be carried out.

In this paper we present the results of these field trials, which ultimately led to a very successful and profitable field development strategy. A variety of very challenging operational problems were encountered, and solved. Reference is made to injection nozzle blockages, fouling of glycol gas dehydration systems, severe scaling problems in production and downstream water treatment/injection facilities, inadequate hydrogen sulphide removal efficiencies and HS&E related issues. A better understanding of the fundamental relationships between operating parameters governing direct-injection processes and associated chemical development and application methods has been gained. Communication and integration of experience and knowledge between the operating unit and its chemical supplier were key success factors in this achievement, as was the endurance and continuing support of field operations staff in facilitating the resolution of difficult problems.
Survey of Successful World-Wide Asphaltene Inhibitor Treatments in Oil Production Fields
Authors: Cenegy Lawrence M.
Published: December 2007

Asphaltene deposition problems have been known to occur world wide, with serious asphaltene deposition problems being associated with oil fields in Venezuela, the Persian Gulf, the Adriatic Sea and the U.S. Gulf of Mexico. Until recently, these problems were resolved in producing fields by the use of chemical solvents, or by pigging, scraping or other mechanical means of asphaltene removal. Recent advances in asphaltene inhibitor technology have provided cost-effective methods of preventing deposition and, in many cases, increasing the production of the wells being treated.

This paper will provide field data relating to the on-going successful asphaltene treatment programs being conducted in above-mentioned oil producing regions around the world. In these cases, large revenue increases were noted by the producers due either to an increase in production or reduced maintenance costs. The paper will detail the specific field parameters as well as the process employed for treating the systems. A cost, and return-on-investment will also be calculated for the treatments, where possible.
A New Method to Locate Partial Blockages in Subsea Flowlines
Authors: Liu Liang J. , Scott Stuart L.
Published: December 2007

As exploration and production operations move into deeper waters, producers are faced with new flow assurance challenges. One problem associated with deepwater production is the deposition of paraffins, asphaltenes, hydrates, and scale within the pipeline. These depositions form partial pipeline blockages that reduce flow capacity and may ultimately put the subsea flowline at risk. Pigging and other intervention techniques can be used to deal with this problem. This paper develops a method for locating partial gas pipeline blockages and estimating their size. This method can be used to provide important information for monitoring chemical inhibition programs, scheduling pigging, assessing risk for pigging and planning other intervention procedures.

This paper considers the application of the average pressure method as a new means of locating partial blockages in subsea flowlines. When a blockage occurs in a flowline, it will change the steady-state pressure profile and reduce the average pressure in the flowline. The average pressure is determined through a simultaneously shut-in test (SSIT). Calculation examples show the procedures and range of application of this new technique.
Deepwater Separation: What Could Be the Use of it?
Authors: Johansen O. , Leporcher E.
Published: December 2007

A few years ago, sub-sea gas/liquid separation was sometimes contemplated as an alternative to multiphase boosting to extend the distances of multiphase transportation. In deepwater environment, and mainly in case of a sub-sea scheme, the down-hole fluids follow quite a different route. This difference takes place in the topography of the system (smaller depth of the well, sub-sea flow-line, longer length of the riser system) and in the thermodynamics (temperature and pressure profiles). TOTALFINAELF is involved in several sub-sea and deepwater operations. A preliminary analysis of fluid flow conditions in a sub-sea deepwater export system allows differentiating the impact of the water in the seabed pipeline network from the impact of the water in the riser system. This paper will present the water impact along the transportation system, it will make a review of existing and possible technology able to handle the fluids through separation process (Water/hydrocarbon and gas/liquid separation) to ease the fluid transfer from the sub-sea wellhead to topsides facilities, at the end it will discuss the most likely cases of application, its ability to face unexpected operating conditions (and subsequent cost consequences). An analysis of implementation strategy will be described: Where would subsea separation stand in competition to other technologies?
Conversion of Water to Hydrate Particles
Authors: Larsen R. , Lund A. , Andersson V. , Hjarbo K. W.
Published: December 2007

A concept, CONWHYP (CONversion of Water to HYdrate Particles), has been developed in which a recirculation stream containing hydrate particles seeds hydrate growth in a cooled water-containing well stream. The hydrate particles then grow quickly and in a controlled manner. The hydrate particles are dry, non-depositing and non-agglomerating, and will eliminate free water from the rest of the transport system. The concept has been tested and verified in a prototype laboratory setup. The results include general observations of dry hydrate behavior, experiments on water content, hydrate particle morphology, and salt and "black oil" effects. Some possible designs for industrial application of the concept as a subseaprocessing unit for multiphase flow solutions in harsh environments are outlined.
Statistical Assessment and Management of Uncertainty in the Number of Electric-Submersible Pump Failures in a Field
Authors: Sawaryn S. J. , Ziegel E.
Published: December 2007

Successful management of a population of Electric Submersible Pumps (ESPs) requires an accurate estimate of the expected number of failures as a function of time plus a determination of the associated uncertainty. Knowledge of the uncertainty is required for an effective risk assessment to be made of workover strategies and the impact of these strategies on the production economics. Though the oilfield literature contains discussions of the models and methods for estimating the expected number of ESP failures, little discussion has been presented on the confidence of such estimates.

This paper contains details of how the choice of model, parameter estimates and variation in a well's economic criteria affect the confidence limits. It shows that the uncertainties inherent in the continuous replacement of ESPs and the estimation of their run lives may make the estimates of the number of failures across an entire field to be numbers with considerable uncertainty. This effect is particularly pronounced during the first few years after field start-up. Under these circumstances the distribution of the number of failures is skewed and a 60% difference between the estimated and recorded number of failures is possible. Statistical models also enable differentiation in performance between manufacturers and technologies. It is shown that even large differences in measured run life may not be conclusive evidence of technical or manufacturing superiority. Based on these results, actions are suggested to reduce the uncertainty and improve the management of a field.
Experimental Investigation of Two-Phase Flow Performance of Electrical Submersible Pump Stages
Authors: Pessoa Rui , Prado Mauricio
Published: December 2007

Two-phase flow behavior prediction of centrifugal pumps is a hard task due to the complexity involved in modeling multiphase flow inside turbo machines. No models are currently available for this purpose. Some empirical correlations are available in the literature, but they are valid only for the tested pumps in the experimental range used to develop them. An experimental study has been conducted at The University of Tulsa Artificial Lift Projects - TUALP with a 22-stages GC6100 pump to gather data for pump performance under two-phase flow conditions. Air and water were used as working fluids. This study differs from other experimental works because the pressure changes were recorded stage-by-stage. The results of previous works have been reported as an average of the intake and discharge conditions, and depend on the number of stages used.

Phenomena like surging and gas locking were observed during these tests and their boundaries have been mapped. It will provide some insight regarding when they appear, and the way they are revealed.

The pressure increment and total hydraulic horsepower for the average pump and per stage as a function of the liquid flow rate, and each gas flow rate considered are presented. The average brake horsepower and efficiency for the pump are also plotted for the variables mentioned.

The results indicate that the average behavior for the pump is significantly different from that observed per stage.
Production Optimization using Multiphase Well Testing: A Case Study from East Kalimantan, Indonesia
Authors: Retnanto Albertus , Weimer Ben , Kontha I Nyoman Hari , Triongko Heru , Azim Azriz , Kyaw Htun Aung
Published: December 2007

A multiphase flow meter named PhaseTester has been developed for determining oil, water, and gas production rates simultaneously. This new approach of well testing delivers significantly improved data quality and availability, allowing quick well performance trend analysis and immediate well diagnosis. Rapid, accurate production diagnosis allows timely decisions without prior well information or standard rate stabilization periods resulting in shorter, more reliable well tests stored in an easily accessible, user-friendly database.

The PhaseTester provides a comparatively lighter operation unit and reduces risk of human error resulting in improved safety. Compared to conventional units, the physical size of the PhaseTester is usually half the size and the extensive pressure lines and safety devices are reduced. The meter is environment friendly since all the well effluents are returned to the production flowline without the need for separation or burning of hydrocarbons during the test.

Obtaining periodic, accurate well test measurements is the key factor in Vico Indonesia Indonesia's well production optimization. The PhaseTester was introduced to monitor and optimize the production performance for gas lift wells. Changes in well performance were observed immediately allowing the operations engineer to quickly analyze the production characteristics and make decisions based on true accurate real time test data. Selected case histories demonstrate the results of these tests.
Multiple Factors That Influence Wireline Formation Tester Pressure Measurements And Fluid Contacts Estimates
Authors: Proett Mark A. , Chin Wilson C. , Manohar Mohan , Sigal Richard , Wu Jianghui
Published: December 2007

Pressure measurements using conventional wireline formation testers (WFTs) can be influenced by near-wellbore effects such as mudcake buildup and filtrate invasion, which are coupled physical events. These combined effects can change the interpretation of the pressure data, shifting the gradient curves and the fluid contact depths.

Recent papers have discussed corrections for wettability and for capillary pressure effects on formation tester measurements, the next steps needed for improved predictive measurements.1,2,3 Suggestions by different investigators have stimulated interest in several research directions. Because the foregoing effects are the result of mud filtrate invasion, which normally involves multiphase flow, it is necessary to quantify all competing results using a numerical simulator that models all effects rigorously. The work described in this paper models the complete process quantitatively with an invasion simulator that includes the dynamically coupled effects of mudcake growth and multiphase, immiscible filtrate invasion.

The simulator is used to model the invasion profile, that is, the changing oil-water ratio while pumping. It includes wettability and capillary pressure effects. Many of the parameters predicted in the simulation can be crosschecked from log data, including mobility estimates from WFTs and fluid saturations from NMR and array induction logs. Modern WFTs such as the Reservoir Description Tool (RDT) can monitor the fluid properties while pumping.4 This information can, in turn, be used to determine the volume fractions of the produced fluids. The same simulator used for invasion is used to match pump-out results and determine supercharge (i.e., elevated pressures near the wellbore) and capillary pressure effects.

Several field examples are used to illustrate how these methods are combined to correct pressure measurements, gradients, and fluid contacts.
Deconvolution of Well Test Data as a Nonlinear Total Least Squares Problem
Authors: von Schroeter Thomas , Hollaender Florian , Gringarten Alain C.
Published: December 2007

Finding a good algorithm for the deconvolution of pressure and flow rate data is one of the long-standing problems in well test analysis. In this paper we give a survey of methods which have been suggested in the past 40 years, and develop a new formulation in terms of the logarithm of the response function. The main advantage of this nonlinear encoding over prior methods is that it does not require explicit sign constraints. Moreover we introduce a new error model which accounts for errors in both pressure and rate data; here the rates can be cumulative or continously measured.

In this formulation, deconvolution is equivalent to a separable nonlinear Total Least Squares problem for which standard algorithms exist. Preliminary numerical results with both simulated and field data suggest that the method is capable of producing smooth, interpretable reservoir response estimates from data contaminated with errors of up to 10% in rates, provided a careful choice of weight and regularization parameters is made.
Interference Testing with Horizontal Observation Wells
Authors: Al-Khamis M. , Ozkan E. , Raghavan R.
Published: December 2007

Interference and pulse tests at horizontal wells introduce features and issues that require specific procedures for evaluation and analysis. In addition to reservoir properties, it becomes necessary to account for three-dimensional pressure distributions, as horizontal wells tend to be rather long. The objective of this paper is to discuss the effect of the existence of a horizontal observation well on the analysis of interference tests.

We use a semi-analytical model for interference testing with a horizontal observation well. The conductivity of the horizontal wells may be infinite or finite. We discuss the flow regimes in the observation well. The effect of anisotropy is shown to significantly affect the interference between two horizontal wells.

In many practical situations, it becomes necessary to evaluate such tests by numerical means. At this time, no simple method exists to calibrate observation well responses computed by numerical simulators. The results of this study should provide for an accurate measure of pressure responses to calibrate numerical simulators.
Transient Pressure Response of Fluvial Reservoir With Branching Channel and Splay
Authors: Zhao Gang , Thompson Leslie G.
Published: December 2007

Fluvial reservoirs with branching channels and splays comprise a commonly encountered depositional system, however, characterization of this type of system using transient pressure analysis has not yet been fully explored. This article presents a semi-analytical method to compute the transient pressure and pressure response for this system type. It simplifies the computation by decoupling the complex-geometry system into a discrete set of simple-geometry systems that are in hydraulic contact with each other, and exchange fluids at their hydraulic contacts[1,2]. The computed pressure and pressure derivatives were compared with those of other simple well/reservoir systems to gain insight into the information contained in the responses. The source and sink method[3] was used to compute the pressure response in the Laplace domain and the results were inverted numerically using the Stehfest Inversion algorithm[4]. The discussion in this paper is focused on four cases, consisting of a main channel and a side branch that connects with the main branch at angles of 30, 45, 60 and 90 degrees, respectively. In each of these cases, the set of "image" wells that create no-flow boundaries is easy to generate, and an efficient computational algorithm is developed. Excellent pressure and pressure derivative responses have been obtained; detailed examination of these responses provides insight into methods that may aid in the identification and characterization of this type of system.
Evaluation of the Effects of Heterogeneity, Grid Refinement, and Capillary Pressure on Recovery for Miscible-Gas Injection Processes
Authors: Solano Reinel , Lee Sheng-Tai , Ballin Paulo R. , Moulds Tim P.
Published: December 2007

Large grid blocks, usually required to perform field scale reservoir simulations, introduce artificial numerical dispersion that may lessen the effect of other dispersion mechanisms like diffusion, dispersive mixing, or capillary pressure. The effect of diffusion and dispersive mixing on recovery in miscible gas injection may be approximated by numerical dispersion. Capillary pressure effect, instead, should be explicitly evaluated.

Previous works performed at BP have shown discrepancies about the effect of capillary pressure on recovery for miscible gas displacements. The discrepancies seem strongly related with the particular permeability distribution and injection conditions used to perform the evaluation. Therefore, this project attempts to evaluate simultaneously the effects of heterogeneity, capillary pressure and grid refinement on recovery.

The simulated process consisted of WAG injection of an enriched gas in a stochastic 2-dimensional cross-section. The results show that capillary pressure increased oil recovery when Lorenz Coefficient (LC) was less than 0.5 and reduced oil recovery for very heterogeneous reservoirs, LC greater than 0.6. Oil recovery decreased significantly with increasing heterogeneity when LC was greater than 0.4. Grid refinements performed in the horizontal direction had a minor impact on oil recovery; on the other hand, the impact of vertical grid refinement depends on specific conditions of capillary pressure and heterogeneity.

The results demonstrate the importance of capillary pressure in the reservoir model for miscible-gas displacements. In addition, this work gives some guidelines to estimate when capillary pressure has greater impact.