bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multiphase Pumping - Operation & Control
Authors: de Salis J. , de Marolles Ch. , Falcimaigne J. , Durando P. 
Published: December 2007

Abstract
This paper reviews field issues related to the planning, installation and operation of the helico-axial multiphase pumps.
Interest for multiphase production, which leads to simpler and smaller in-field installations, is primarily dictated by the need for more a cost effective production system.
Multiphase pumping is essentially a means of adding energy to the unprocessed effluent which enables the liquid/gas mixture to be transported over long distances without the need for prior separation.
The Poseidon helico-axial pumps, under normal operating conditions, are largely unaffected by process fluctuations at pump inlet (changes in pressure, liquid or gas flow rate). They have demonstrated a stable behaviour (self-adaptive capability with regards to instantaneous changes).
A multiphase pump set is designed to operate under changing/fluctuating process conditions.
An important issue related to pump operability and flexibility has to do with the driver selection: fixed speed vs. variable speed In some cases a fixed speed drive provides sufficient operational flexibility. In other cases variable speed can be chosen.
Pump operation & control strategies are presented and discussed.
Recommendations and guidelines for the field system designer are given.

Introduction
When the production of a marginal field or a group of remote wells is considered with an existing central gathering system the traditional options for field development are:–natural flow,–artificial lift,–in-field separation with crude oil transfer pumps, gas to flare, or gas compression systems.
With the recent field deployment of numerous multiphase pumps (MPP) new approaches to field development and production have been demonstrated. Typically helico-axial MPP have accumulated over 35,000 operating hours with an average availability of approximately 90%.
Considering multiphase flow transient behaviour the operability of MPP is highlighted in the case of a declining offshore field with an increasing water cut.
Different levels of pump control are defined depending on the operational requirements. Building on previous ideas a novel control system is introduced.

Pump Specification
The multiphase pump selection cannot be based solely on one defined operating point (main duty point) as it is commonly done for process pumps or compressors for refinery duty. Field experience shows that actual operating conditions change during the field life and may be different from predictions.
Therefore multiphase pumps should be designed to be capable of facing different operating parameters by having a wide working envelope.
Flow rates and pressure predictions are bound with uncertainty. The design of production facilities is generally based on extrapolations from the results of exploration well tests, delineation wells and reservoir characterisation.
As a result, when the production wells are drilled and completed, the actual production data may be different from the prediction.
P. 193
Completion Ranking Using Production Heterogeneity Indexing
Authors: Reese R.D. 
Published: December 2007

Abstract
This paper describes an analysis method for production data referred to as heterogeneity indexing which quantifies well performance anomalies for the purpose of assessing completion efficiency. It has been proven useful for determining the most successful completion practices in a given area and formation as well as a surveillance tool for primary and secondary recovery operations.
Utilizing computer aided normalization methods, heterogeneity signatures and indexes may be extracted from time-based production data. The paper illustrates how to calculate these indexes, integrate this information with petrophysical and completion data, and then interpret it for the purpose of assessing the effectiveness of various types of completion methods. In developing this method, fluid simulation modeling of various types of reservoir heterogeneities were used to develop a series of type curves. The signatures in these type curves exhibit characteristics which have been shown to relate to reservoir properties and completion efficiency.

Introduction
When subjected to appropriate analysis methods, oil and gas production data exhibit well performance anomalies useful to the assessment of completion efficiency. This information can be used to rank the effectiveness of different completion methods being used with a particular producing formation in a given geographical region. Completion efficiencies are also useful for identifying specific wells with poor or superior performing completions. An analysis method referred to as heterogeneity indexing may be used for this purpose. It involves the computer analysis of historical production data which is then integrated with available completion and rock data to develop performance ranking criteria and assessment tools.

Production Heterogeneity Indexes
Anomalies are observable in oil and gas well production data that are attributable to one or more of the following factors:
Time well is on production Reservoir pressure Completion method and efficiency Reservoir quality and tank size With proper analysis methods, the effect of the first two factors can be normalized out so that assessment of completion efficiency and/or reservoir quality becomes possible. This assessment is accomplished with heterogeneity indexing which may be generally defined as follows:
where HI Fluid is the heterogeneity index for any type of fluid production ratio. Fluid may be oil, gas, barrels of oil equivalent, total liquid, gas-oil ratio or water cut and may consist of either "rate" or "cumulative" numbers.
A well with no heterogeneity (an average well for the field or formation) has an HI equal to 1.0. When HI is examined over n periods of time, a heterogeneity signature is obtained. An example is shown in Figure 1. The shape of this signature, relative to the benchmark of HI = 1.0, can be indicative of completion or reservoir anomalies.
P. 303
Use of Second Pressure Derivative for Automatic Model Identification in Well Test Analysis
Authors: Bourgeois Marcel J. , de la Combe Jean-Luc Boutaud , Ajjoul Mohamed 
Published: December 2007

Abstract
This paper deals with automatic model identification in the analysis of pressure transients. The choice of the model, sometimes called diagnostic, is one of the first steps in the interpretation process, and it is important as it affects the values of the parameters deduced from the match.
This diagnostic is traditionally based on the shape of the derivative, plotted on a log-log scale. The shape of this derivative can be described with the second derivative, which is defined as the slope of the conventional derivative on a log-log plot. This second derivative can be computed and coded after smoothing, filtering and segmentation of the measured data. Several reservoir models can then be proposed, as they are chosen in accordance with the data base of previously interpretated well tests.
This 3-year project was ambitious as its goal was to recognize not only the usual models with a characteristic signature, but also those which the interpretator would sometimes overlook.

Introduction
Diagnosing all possible reservoir models from a pressure derivative curve is not a simple task, and automating this aspect of a pressure transient analysis is understandably attractive. This paper describes the development of such an automation technique, using the second pressure derivative curve prior to parameter estimation.
The listing of possible reservoir models corresponding to the measured response will sometimes remind the user of some models or combinations which are not common or straightforward.

Methodology
The main difficulties in the automatic analysis of real data, especially using the pressure derivative, are the separation of the true reservoir response from wellbore or gauge effects, and then to associate the signal to a known reservoir model. To do so, the following steps are followed:

1) Preprocessing of data
The data are considered to be a distribution of points, which are smoothed with a function passing through them so as to minimize the differences between measures and approximation. This is the ((diffuse approximation)) approach. This function is filtered with a low-pass Butterworth filter of order 2.

2) Segmentation of the second derivative
This step is performed with a split and merge algorithm. It should be robust, but still exact enough to detect even incomplete or short reservoir responses.

3) Coding
This segmentation is then coded in alphabet-attributes to establish the relationship between shape description and knowledge of about 30 base models. Finally, this coding is split into one, two or three coherent subsets to enable the correct interpretation (well, reservoir, boundaries) as a composition of the base models.
P. 959
Seabed Rawwater Injection : An Alternative Pressure Maintenance System
Authors: Waite R. J. , Eden R. , Cousins A. R. 
Published: December 2007

Extended Abstract
Introduction. In the search for improved value from their offshore developments, oil companies have focused on a number of technology initiatives aimed at reducing facilities costs. One such initiative focuses on the use of raw seawater injection for reservoir pressure maintenance.
Traditionally, seawater undergoes significant and costly treatment prior to injection; typically this involves deoxygenation and dosing with various combinations of free chlorine, other organic biocides and corrosion inhibitors.
A number of oil companies have, in recent years, questioned the need for such treatment, suggesting that untreated, raw (but chlorinated) seawater could deliver adequate reservoir pressure maintenance at significantly lower cost.
Comparison of Perforating and Notching a Horizontal Wellbore for Hydraulic Fracturing
Authors: Underwood Porter J. 
Published: December 2007

Abstract
In horizontal well fracturing operations, minimized wellbore entry to the formation improves fracture placement and enhances production response. Generally, operators most commonly jet-perforate along a 1- to 5-ft interval to connect the wellbore with the formation, but a new method is available in which water-entrained sand is used to notch the casing. Slurry is then pumped through a jetting nozzle to complete the operation. To compare the two processes, operators performed an eight-stage fracturing treatment in which alternating stages of conventional jet-perforating and treatments with the newly designed jetting tool were both used.
Oil Recovery in Fractured Oil Reservoirs by Low IFT Imbibition Process
Authors: Al-Lawati Shabir , Saleh Saad 
Published: December 2007

Abstract
This paper presents the results of an experimental study performed to investigate the effect of reduced interfacial tension (IFT) on oil recovery by spontaneous imbibition and gravity segregation. The results of the static imbibition experiments, in which a matrix block was surrounded by the imbibing fluid, showed that a minimum Bond number (NB-1) was required to increase the final oil recovery. However, the reduction of the IFT may increase or decrease the rate of imbibition substantially depending on the relative contribution of capillary and gravity forces. The results of the experiments performed on three ranges of permeabilities with four different surfactant solutions (different IFT values) showed that imbibition can occur in three different regimes: capillary dominated, gravity dominated, and a regime in which both forces affect the imbibition process.
In order to examine the effect of IFT on oil recovery on the same core, core wettability has to be restored after each test. Several cleaning procedures were investigated to reproduce original core wettability. As an outgrowth of this research, a core cleaning technique for restoring core wettability has been suggested. Firing the core after toluene cleaning for seven hours at 950 F was found to be an effective procedure to restore core wettability after solvent extraction. The same procedure also proved effective for restoring the original core wettability after surfactant solution imbibition tests.
Imbibition has been recognized as an important factor in recovering oil from water-wet fractured reservoirs subjected to waterflood or water drive. Water imbibition is the process by which water flows into porous media by capillary forces. These forces allow the water to flow from the fractures into the water-wet, oil-saturated matrix blocks, which causes the oil to be displaced from the matrix into the fracture. Unfortunately, water imbibition is inefficient in recovering oil, often leaving more than half of the original oil-in-place unrecovered.
A static imbibition by surfactant solution imbibition process recovers residual oil by reducing the surface forces between the oil and the imbibing fluid. On the other hand, by reducing the interfacial tension, the capillary forces that cause imbibition are reduced.

Objective:
The objective of this static imbibition work is to investigate the effect of reducing IFT in different oil/water/rock systems on final oil recovery.

Methods of Investigation:
Sets of experiments were performed by using a specially designed static imbibition apparatus. Each experiment consisted of exposing an oil-saturated Berea sandstone core to water imbibition (base case), cleaning and saturating the core with the same oil, and exposing it to surfactant solution imbibition. Oil recovery by water and surfactant solutions imbibition from each core are compared.
P. 107
A New Approach to P/Z Analysis in Abnormally Pressured Reservoirs
Authors: Guehria Fawzi M. 
Published: December 2007

Abstract
Future performance of gas reservoirs can be predicted if one identifies the main drive mechanisms and the original gas-in place. The extrapolation of the p/z versus cumulative gas production plot is a commonly accepted method that is used to estimate original gas in-place in volumetric gas reservoirs.
However, abnormally pressured reservoirs usually exhibit initial pressure gradients in excess of 0.65 psi/pt at depths greater than 10,000 ft. As a result, in addition to fluid expansion, gas is produced by sand grain expansion, rock compaction and water expansion. As formation compressibility approaches gas compressibility, the standard p/z curve tends to bend downward, making "straight line extrapolation" questionable. To account for this compaction phenomenon, some authors suggested to modify the material balance equation by incorporating constant pore and water compressibilities.
Unfortunately, by assuming a constant pore compressibility, the original gas in-place can be overestimated by as much as 60%. These errors are caused by pore compressibilities continually changing as fluids are withdrawn and as pressures decline to a normal range. To overcome this shortcoming, we propose to rigorously account for the variation of pore compressibility with pressure.
Assuming that pore compressibility as a function of pressure is available, a straight-line method which allows estimation of original gas in-place is presented. If pore compressibility is not readily available, we show that by adopting simplified models for pore compressibility versus pressure, we can regress on measured gas production versus reservoir pressure data to obtain initial gas in-place and parameters for pore compressibility model. Regression is performed using a public-domain Levenberg-Marquardt algorithm, and the model parameters are constrained using simple previously-published algorithms.
We demonstrate the validity of our approach by considering synthetic data from a finite difference simulator. We also successfully apply our analysis to data from two abnormally-pressured fields.

Introduction
The observed behavior of abnormally pressured reservoirs has been discussed in the literature.
P. 249
World Wide "Tier" 3 Response
Authors: Neilson D.E. 
Published: December 2007

Abstract
Tier three response to major incidents is not a common occurrence. However when this level of response is required it must be swift and seamless. Oil spills that need an international response may not always be large, location and lack of infrastructure my be some of the main drivers. If a Tier 3 response is not carried out quickly the effort required and the consequences increase. This paper discusses the issues to be overcome and methods to bring about a successful Tier 3 response.

"Tier" 3 Response
The term has two possible meanings. One, that is normally used within the United States and one normally used through out the rest of the world. The US interpretation would be a level of response to counter a worst case spill within an organisations response planning standards. This would be a situation that required cascade of extra response equipment from "out of region" equipment stockpiles. The international understanding is similar. The incident would be one that out striped the local "Tier" 1 and regional "Tier" 2 capabilities. The situation would then require international assistance. As already stated, international assistance may well be required because neither Tier 1 or Tier 2 capabilities exist at, or near the spill location. (Fig 1)

Key Requirements
The key requirements of a Tier 3 response organisation are :-–To provide an effective response world-wide–Hold well maintained state of the art equipment (suitable for air transportation).–Able to provide highly trained, self motivated staff.–Retain a logistical capability.
As with most successful organisations an effective Tier 3 response facility will have suitable equipment and well trained, motivated staff. People are the key to making things work. Tier 3 response organisations have to function in many differing geographical regions. Often, with little support infrastructure. Climate, language, certain political and cultural differences all have to be understood. Equipment that Tier 3 organisation hold normally requires to be air transportable. The selection of equipment for such organisations requires the careful consideration of a number of factors. Size, weight, suitability for different spilled oil characteristics and maximum possible recovery efficiency, all have to be considered during this process. A successful Tier 3 organisation must maintain a high level of logistical capability with a heavy focus on aviation.

Emergency Response
If the response to a Tier 3 oil spill incident is not carried out swiftly and effectively, the consequences for companies can be far reaching. The ability to provide a successful response becomes difficult. The effort and therefore cost to the company increase tremendously. The consequences and damage to the company image can be catastrophic.
Solvent Stimulation of Viscous Crude-Oil Production
Authors: Gates G.L. , Caraway W.H. 
Published: December 2007

Abstract
To improve both the rate and volume of production of viscous crude oils, the USBM made a production of viscous crude oils, the USBM made a study of solvents to stimulate production. Five laboratory methods were used to evaluate the effectiveness of several solvents in the stimulation of viscous oil production. These methods were (1) viscosity reduction, (2) gravity drainage production from sand columns, (3) displacement from capillary tubes, (4) effect of organic acids on crude oil viscosity and (5) hydrocarbon analysis. Solvents ranging from refinery cuts to chemical compounds were used with six California and one Kansas crude oils. Results indicated that small quantities of effective solvents greatly reduced the viscosity of viscous crude oils. The rate and volume of production of viscous crude oils by gravity production of viscous crude oils by gravity drainage from laboratory sand columns were increased greatly by small quantities of effective solvents. It was also found that low molecular-weight aromatic-hydrocarbon solvents effectively removed viscous crude oils from glass capillary tubes.

Introduction
Because of the rapidly growing national demand for energy, a study was made by the USBM of improved methods for producing viscous crude oils. Previous USBM studies showed that over 100 billion bbl of viscous crude oil are present in over 2,000 petroleum reservoirs. present in over 2,000 petroleum reservoirs. California has the largest resource of viscous crude oil — about 75 percent of the oil classified as most favorable for recovery by stimulative methods. Exploration costs for viscous oils are almost nonexistent because the large reserves are in known fields where many producing facilities already exist. Interest producing facilities already exist. Interest in the viscous crude oil resource has been enhanced further by the development of high-yield hydrocracking refinery processes to convert low cost viscous crude oils into valuable fuels. Some hydrocracking processes yield up to 80 percent volatile fuels from viscous oils. percent volatile fuels from viscous oils. In this study, methods of evaluating solvents were examined in the San Fracisco Energy Research Laboratory, and the results obtained using viscosity reduction, sand columns, capillary tubes, addition of organic acids, and hydrocarbon analysis are described.
Previous Related Work Previous Related Work A review of published information (1958 to 1968) showed that stimulation of the production of viscous crude oils in California has been improved by the addition of steam to the reservoir. Stimulation of production of viscous crude oils has been obtained by injecting large quantities of steam to heat the oil above normal reservoir temperature. Improved production by the addition of heat to decrease the viscosity of crude oil in the reservoir has been outstanding in the Kern River field of California where production has increased from 9,500 bbl a day in production has increased from 9,500 bbl a day in 1950 to 70,000 in 1970.