bluuebunny/crossref_metadata_2025_split huggingface dataset:
Viscous Oil Dynamics Evaluation for Better Fluid Sampling
Authors: Cañas J. A. , Low S. , Adur N. , Teixeira V. 
Published: December 2007

Abstract
Productivity potential evaluation in viscous reservoirs has been difficult in the past due to difficulties in native fluid sampling and in-situ dynamic formation testing evaluations. This is the result of the high oil viscosity and the unconsolidated sands in which they are usually deposited, which create limitations to natural flowing and smooth well testing / production.
There is no unique answer to the main question "how do we sample heavy oils in unconsolidated sands". However, from the experience Schlumberger has acquired during years, several modifications have been done to the wireline formation testers (WFT)1, such as the Modular Formation Tester (MDT*), and new modules have been developed which, linked to new best practices, have allowed high viscous oil sampling and in-situ formation testing. Some of the new modules and practices include, the extra large diameter (XLD) probe, dual packer with customized gravel pack screens, extra high-pressure displacement unit pump for low flow rates, advanced down hole flow analysis monitoring (DFA*) and special sampling techniques.
In this paper, we present a methodology, which integrates formation tester pressure and water-cut measurements with detailed reservoir characterization from logs to better understand the viscous oil dynamics in sandstones reservoirs in order to optimize fluid sampling.
A commercial reservoir simulator ECLIPSE* in fully implicit, black oil mode is used to simulate the multiphase flow during WFT pumping. Around the wellbore very fine grids are used, which, linked to a multi-segmented wellbore option, allows to model the clean out (contamination level versus time curve) and fluid drainage for different scenarios of oil viscosity, reservoir anisotropy, drilling fluid invasion, flow rate and WFT position relative to the top boundary.
The modeling results were validated using WFT field data with different rock and fluid properties. Some correlations were developed for field use that estimates filtrate contamination as a function of clean out time for several WFT modules.
A good understanding of the limitations and benefits of each tool under each scenario contributes to a better collaboration in the design and optimization of sampling jobs (best practice and calibration of available analytical planners for field use).
Unlocking the Potential: A North Sea Heavy-Oil Success Story
Authors: Wylde J. J. , Williams G. D. M. , Cousins R. E. 
Published: December 2007

Abstract
This paper gives details concerning one of the newest producing fields in the North Sea, West of Shetland development. Examples of the pre-start up design and implementation challenges are dwelt on, as well as the philosophy taken when commissioning the plant and chemical injection facilities. The majority of the paper focuses on the first 6 months of production history and the way in which the management of production techniques was performed and in particular how actual operations differed to the planned and designed specifications.
With production of a 20° API crude, significant operational challenges have been encountered with initial start up being a staged and controlled process. Details are given to the suite of production chemicals required to give complete flow assurance as well as to maintain plant integrity. The onset of water production brings with it a whole suite of different challenges with by far the most difficult being demulsification and this has been given particular attention.
The Relative Importance of Drawdown and Depletion in Sanding Wells: Predictive Models Compared With Data From the Statfjord Field MM
Authors: Hettema M. H. , Andrews J. S. , Blaasmo M. , Papamichos E. 
Published: December 2007

Abstract
Experience of sand production from the Statfjord field has been systemized to be able to predict the effect of drawdown and depletion on sand production. The aim of the study is to determine how reservoir pressure depletion will influence the sand production and to determine how sand production will influence the maximum liquid production rates. Most wells produce according to a maximum acceptable sand production criterion. Field data based on more than 300 maximum acceptable sand rate tests have been systemized by fitting those to an empirical criterion. For a better determination of the parameters, sand production histories of four wells have been analyzed in detail.
To understand more about the mechanisms underlying the sand production, the field results are compared with four different models. This work concludes that the behaviour of sanding wells at Statfjord can be described by a concept of two sand production regimes, one controlled by shear failure and the other controlled by rate.
Finally the empirical model is used to extrapolate the field experience to low reservoir pressures related to the planned deep depressurization. The results show that sand production will limit well production rates unacceptably for most formations and that downhole sand control is needed to secure high production rates during the late-life development of the field.
Solution Gas Flaring and Venting at Alberta Primary Crude Bitumen Operations
Authors: Ruff C. 
Published: December 2007

Abstract
In August 2005, the Alberta Energy and Utilities Board (EUB) published ST60B-2005: Upstream Petroleum Industry Flaring and Venting Report, which summarizes annual flaring and venting performance from all upstream sources. The report indicated that total solution gas flaring plus venting in Alberta from crude oil and crude bitumen batteries had been reduced to 729 106m3 in 2004 from the 1996 combined flare plus vent baseline volume of 1,808 106m3, a reduction of 59.7%. Of the 729 106m3 flared and vented solution gas, 248 106m3 (34.0%) was attributed to crude bitumen operations, and of this volume, 219 106m3 (88.2%) was the result of venting, with the remaining 29 106m3 (11.8%) being flared.
In September 2000, the EUB, as a member of the Flaring and Venting Project Team of the Clean Air Strategic Alliance (CASA), made a commitment to develop a venting management framework that would promote the reduction of venting from crude bitumen operations. In 2002, the resultant framework was included in EUB Draft Guide 60: Upstream Petroleum Industry Flaring, Incinerating, and Venting. Since then, encouraging reductions in venting at primary crude operations have been realized. The EUB is planning to release an updated version of Guide 60 in 2005 that will contain several enhancements designed to further promote reductions of solution gas flaring and venting.
This paper discusses the following items as they pertain to crude bitumen operations and primary crude operations in particular: Solution gas flaring and venting performance in Alberta to calendar year-end 2004Best practices respecting solution gas conservationCASA recommended enhancements to Guide 60
Development of High-Resolution Axial Flux Leakage Casing-Inspection Tools
Authors: Vogtsberger D. C. , Girrell B. , Miller J. , Spencer D. 
Published: December 2007

Abstract
Well casing and tubing integrity is a very important component in the safe operations of oil and gas wells in the US. To maintain safe operating conditions through out the life of a well, operators must periodically determine the integrity of the downhole well tubulars.
Historically, casing inspection data has been acquired with downhole wireline technology, and predominately with magnetic flux leakage (MFL) inspection tools. Limitations in available electronics, however, have meant that MFL logging tools have thus far been commercially available only in low-resolution configurations. Although proven to be highly robust and effective in downhole inspection applications, all low-resolution MFL instruments incorporate measurement and analysis techniques that limit their ability to precisely resolve defect geometry in all circumstances.
Baker Atlas is in the development of high resolution MFL logging instruments based on hall sensors and other improvements in the magnetic, electronic and mechanical configuration of the inspection system. From an industry survey, a set of requirements for a series of high resolution MFL logging instruments was established. A high resolution MFL instrument design program was then undertaken, incorporating magnetic finite element analysis, mechanical design and electronics design to meet the defined applications. A bench prototype device was used to acquire characterization data in a laboratory environment. The resulting axial flux leakage inspection data was then analyzed to determine the instruments basic defect detection thresholds and sensitivity to changes in defect length, width and depth. Finally, an operational field test device was used in field applications to verify operational performance of the inspection system. This paper will review the development process and outline expected benefits of the tubular inspection system.
These developments of high-resolution MFL logging instruments are intended to produce a more accurate determination of defect geometry, which will provide operators with improved data for casing integrity management.
Refining Geology With the Bit: An Innovative Approach to Well Design and Geosteering
Authors: Lee C. , Foster H. 
Published: December 2007

Abstract
Maximizing bitumen recovery from thermal horizontal wells requires optimal placement of the wellbore close to the bottom of the reservoir. Canadian Natural Resources Ltd. is collaborating with Halliburton to utilize logging while drilling (LWD) techniques to achieve optimal well placement in relatively thin heterogeneous reservoirs of the Clearwater Formation in its commercial cyclic steam stimulation operations in east central Alberta, Canada.
Halliburton's StrataSteer3D ® service is used both prior to, and during, drilling in real time to plan, model, and steer the horizontal well. Resistivity, and gamma ray are monitored in real-time to detect the base of the reservoir during horizontal drilling and thereby geo-steer the well one meter above the reservoir base. Real-time data are used to recalculate well plans as new surveys and petrophysical data are acquired. Data collected are integrated using DecisionSpace ® for 3D geological modeling and well planning. Geological surfaces are revised while drilling and are applied to successive wells. Log responses are also characterized and correlated to the known area geology.
This method of using the bit to steer by, and refine, the geology results in a reduction in overall drilling time by eliminating the need to intentionally ‘tag’ the bottom of the reservoir. Wellbore completion is also improved by ensuring maximum steam contact with the reservoir. The precision of vertical wellbore placement is increased thereby giving greater confidence in subsequent reservoir performance characterization.
A Method for Reservoir Management of Waterfloods
Authors: McLachlan K. , Ershaghi I. 
Published: December 2007

Abstract
This presentation introduces a method for continuous monitoring of water flood performance data whether it be for individual wells, group of wells, or an entire field. Efficiency of immiscible displacement using water injection depends on a number of parameters including mobility ratio, aspect ratio and the heterogeneity index. Cumulative Water Oil Ratio, here referred to as CWOR, can serve as a dimensionless parameter to assess the efficiency of a flood. For typical ranges of these controlling parameters, a simulation based study was conducted covering multiple combinations of these factors. Estimations were made of the expected ranges of CWOR's. These ranged from 1.5 to over 50. Additionally, the buildup trends of instantaneous WOR (IWOR) versus CWOR for various reservoir specific conditions were examined as a monitoring tool to gauge the efficiency of a flood versus the expected asymptotic levels. A procedure is suggested for estimation of reservoir heterogeneity index from comparisons dimensionless plots of IWOR vs. CWOR.
New Progressing Cavity Pump (NPCP) for Multiphase and Viscous Liquid Production
Authors: Bratu C. , Seince L. 
Published: December 2007

Abstract
This paper presents a new pump concept, called the New Progressing Cavity Pump (NPCP). The NPCP is composed of a Progressing Cavity Pump (PCP) and a system of Hydraulic Regulators (HR) installed inside the pump in between the cavities. The HR are self-regulated devices that recirculate the fluid between the cavities in order to control the pump thermo-hydraulic response and to avoid excessive built up of heat, which might result in premature failure of the pump's stator.
It is common knowledge that the traditional Progressing Cavity Pumps (PCP) have shown significant problems when dealing with multiphase mixtures, with high gas void fraction (GVF). We propose a new concept, NPCP, which is able to handle much better such conditions, as its internal hydraulic regulators (HR) recirculate fluid inside the pump. The benefits are multiple. First, it uniformizes the pressure across the pump length, which stabilizes the temperature. Second, it compensates the compressed gas volume of progressing cavities. Furthermore, it protects the stator and therefore, improves the pump's performance.
The relatively small dimensions of hydraulic regulators HR and their distribution along the pump result in an efficient multiphase design. Compared to traditional PCP, the new NPCP system better controls the reliability parameters, such as temperature and friction torque, reduces energy consumption and enhances hydraulic performance (flow rate, delivered pressure).
Several industrial NPCP have been manufactured and tested in liquid, both water and oil, as well in multiphase flow (air and liquid). This paper presents and describes the bench test results and shows that NPCP improves both reliability and hydraulic performance over existing pumps.
Sequential Multiwell Steam Huff ‘n’ Puff in Heavy-Oil Development
Authors: Shuhong W. , Yitang Z. , Liqiang Y. , Kequan Y. , Xia Z. , Chuntao L. 
Published: December 2007

Abstract
Steam huff and puff, generally thought of as a single well process, has seen interwell interactions such as steam channeling and/or watering out of neighboring producer by condensed steam at the later stage resulting in the poor production performance.
In contrast to the single well huff and puff (also named CSS), sequential multi-well steam huff and puff (SMWSHP) is a method in which some wells go to injecting, soaking and producing sequentially or at the same time. This method could avoid steam disturbance and interwell channeling and improve the production performance of huff and puff.
Feasibility study on sequential multi-well huff and puff in developing heavy oil reservoir is presented in the paper. The mechanism and sequence (manner and overlapped time) of SMWSHP and also the pilot test have been studied in a heavy oil reservoir from Xinjiang Oil Field. Both the field pilot test and the theoretical study show that SMWSHP could economically prolong the production period, improve the production performance of steam huff and puff, and increase the oil recovery by 5~7%. The mechanisms of SMWSHP are as follows: (1) Injecting steam into several wells at the same time can avoid the interwell steam channeling, extend the heating area and increase the reservoir pressure. (2) Injecting steam in various sequences could displace oil into different direction and so, improve the sweep efficiency.
The Role of the Value of Information and Long Horizontal Wells in the Appraisal and Development Studies of a Brazilian Offshore Heavy-Oil Reservoir
Authors: Branco Celso C. M. , Pinto Antônio C. C. , Tinoco Paulo M. B. , Vieira Paulo M. F. , Sayd Alexandre M. , Santos Renato L. A. 
Published: December 2007

Abstract
Recent exploration efforts in the Campos Basin, offshore Brazil, have resulted into important discoveries of what is known as "offshore heavy oil" (API gravities below 18 and reservoir viscosities above 20 cp). Actually, these accumulations have been known since the beginning of the development of the Basin, in the 80s, but they were never given a chance of development due to the technology challenges involved. The maturation of lighter oil fields, associated with recent technology developments (1,2,3), has boosted the interest for these heavy oil resources set aside for many years.
This paper describes a case history concerning the strategy for the appraisal of a large offshore shallow carbonate 12 API reservoir, at 100m water depth. To justify the investments in obtaining static and dynamic information of the reservoir behavior, a preliminary development plan based on long horizontal wells was established. The value of the new information (VOI) was estimated through the assessment of the impact that uncertain reservoir and production attributes could have on the development plan. Uncertainty analysis based on reservoir simulation allowed the identification of the main variables affecting the project: reservoir oil viscosity, permeability and effective footage of the horizontal well. This analysis revealed the best strategy for the appraisal of the well planning and led to the approval of a 2000m horizontal well.
On a second stage of the study, after the successful drilling and testing of the well, another VOI study was carried out, aiming at the evaluation of the benefits of a one-year extended well test, which is planned to start in 2007. At this stage, the main reservoir uncertainty was the aquifer support, which could relief the need for sea water injection (besides this there are other production uncertainties as flow assurance, performance of the pumping system and oil water separation).
This paper describes the simulation model building process, the difficult task of assigning scarcely sampled rock and fluid properties, the uncertainty study and the use of quality maps for placing the wells. Simulations results have shown the importance of the well footage and its effectiveness in contacting the reservoir rock.
Top-Injection and Bottom-Production (Tinbop) Cyclic Steam-Injection Method Enhances Oil Recovery
Authors: Matus E. , Mamora D. D. 
Published: December 2007

Abstract
We have developed a novel method to enhance oil production during cyclic steam injection. In the Top-Injection and Bottom-Production (TINBOP) method, the well contains two strings separated by two packers (a dual and a single packer): the short string (SS) is completed in the top quarter of the reservoir, while the long string (LS) is completed in the bottom quarter of the reservoir. The method requires an initial warm-up stage where steam is injected into both strings for 21 days; then the LS is opened to production while the SS continues to inject steam for 14 days. After the initial warm-up, the following schedule is repeated: the LS closed and steam is injected in the SS for 21 days; then steam injection is stopped and the LS is opened to production for 180 days. There is no soak period.
We have simulated and compared the performance of the TINBOP method against that of a conventional cyclic steam injector (perforated across the whole reservoir). Three reservoir types were simulated using 2-D radial, black oil models: Hamaca (9°API), San Ardo (12°API) and the SPE fourth comparative solution project (14°API). For the first two types, a 20×1×20 10-acre model was used that incorporated typical rock and fluid properties for these fields.
Simulation results indicate oil recovery after 10 years are 5.7–27% OIIP with TINBOP, i.e. 57–93% higher than conventional cyclic steam injection (3.3–14% OIIP). Steam-oil ratios are also decreased with TINBOP (0.8–3.1) compared to conventional (1.2–5.3), resulting from the improved reservoir heating efficiency.
Managing Well Integrity, Safety, and Production Decline Caused by Scale
Authors: Al-Ashhab J. K. , Petrone D. , Mokhtar S. R. 
Published: December 2007

Abstract
This work will describe the management of scale in a United Arab Emirates offshore carbonate reservoir. Field pressure is sustained by water injection, which contributes to the formation of scale in downhole tubulars. This scaling can cause both safety and production problems, for example, by blocking a subsurface safety valve or chocking flow at downhole nipples.
ZADCO has initiated a successful strategy to manage the sulfate-scaling tendency in the completion tubing. Software is used to identify wells early on as potential scale candidates. This software uses real field measurements and analysis of injected and produced water information. The results are used to plan well monitoring and/or treatment. The identified wells are monitored using both slickline gauge measurements to measure actual scale growth and produced water surface analysis to update the software model.
Early corrective action is performed using a specialized sulfate scale-dissolving fluid pumped from the surface. More aggressive treatment for larger scale accumulations is performed using a barge, coiled tubing unit, and specialized downhole jetting system.
Results have shown that early diagnosis of the scale allows earlier, easier, and far less expensive scale removal treatment. The effect of scale on production decline is also reduced.
Rheology of Heavy-Oil Emulsions
Authors: Alboudwarej H. , Muhammad M. , Dubey S. , Vreenegoor L. , Saleh J. 
Published: December 2007

Abstract
Water is invariably produced with crude oil. If there is enough shear force when crude oil and produced water flow through the production path, stable emulsions may be formed. This scenario may particularly be present during the production of heavy oils where steam is used to reduce the viscosity of heavy oil or in cases where submersible pumps are used to artificially lift the produced fluids. To efficiently design and operate heavy oil production systems, knowledge of the realistic viscosities of the emulsified heavy oil under the actual production conditions is necessary. This study is an attempt to investigate the effect of water content, pressure and temperature i.e. operating conditions on the viscosity of live heavy oil emulsions.
Two heavy oil samples from South America were used for this study. The stock tank oil (STO) samples were recombined with the corresponding flash gases to reconstitute the original reservoir oil compositions. Live oil-water emulsions were prepared in a concentric cylinder shear cell using synthetic formation water, under predetermined pressure, temperature, and shear conditions. The stability of live emulsions was investigated using a fully visual PVT cell, while viscosities were measured using a pre-calibrated high-pressure capillary viscometer. Viscosities were measured at least in three different flow rates at the testing conditions. In addition to live oil emulsion studies, the stability and droplet size distribution of STO emulsions were also determined.
Experimental results indicated that the inversion point for the stock tank oil emulsions was approximately 60 % water cut (volume) and that the average droplet size was increasing with water content. For all measured cases, viscosities varied with temperature according to an Arrhenius relation while viscosities did not indicate any variation with flow rate (shear) within the range of tested flow rates. Measured viscosities also increased as pressure decreased below the bubble point of the sample as lighter hydrocarbon components evolved. The measured viscosities increased as much as 500% due to the presence of emulsions before sharp drop in viscosity beyond the inversion point. The variation of viscosity with water content for live emulsion samples indicated that the inversion point for live emulsions is similar to that of stock tank oil samples.