bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Fluid Input Wells by Shut-In Pressures
Authors: Groeneman A.R. , Wright F.F. 
Published: December 2007

Introduction
The need for a simple and economical way of determining the operating efficiency of input wells has been evident for many years. Considerable time and money is spent each year in the maintenance of injection wells. Often the results obtained by work-over operations and various treatments do not pay back the extra cost. A method is needed to determine which wells can be expected to respond favorably to treatment. The application of build-up analysis to input wells, both water and gas, is helping greatly ill solving the problem.
The purpose of this paper is to show how the conventional build-up equations can be applied to fluid input wells, how the results are used to evaluate the wells' input efficiency, and to give examples of field tests.

Build-Up Equation
The use of pressure build-up curves in evaluating producing wells has been a valuable tool in the oil industry, particularly in the last few years. The mathematical analysis of these pressure vs time curves has been treated by several authors, some of whom are listed in the references.
More recently it has been confirmed that these same equations are applicable to water injection wells and also to gas injection wells, with some restrictions. The equations used for this study are given in Fig. 1.

Application To Input Wells
The application of these build-up analysis equations to input wells can disclose many useful things about the well and the formation. These include the relative amount of damage or improvement existing in the formation immediately at the wellbore. A comparison of these tests before and after workovers will indicate the degree of success accomplished by the well treatment. These analysis also furnish a yardstick to measure the effectiveness of different well completion methods. They provide a guide to use in a selective plugging program as well as determining the extent of formation fractures. When the effective permeability is considered in conjunction with the skin effect, the injection rate, and the injection pressure, a better understanding of the well's performance is usually reached.
One requirement for the use of these equations is that enough of the injected fluid must be in the formation to insure that the measured pressure drop occurs in that phase only. Minor adjustments may be necessary in some gas input wells for the compressibility factor as well as the weight of the gas column.
Ultrasonic Removal of Organic Deposits and Polymer-Induced Formation Damage
Authors: Roberts P. M. , Venkitaraman Adinathan , Sharma M. M. 
Published: December 2007

Summary
Experiments were conducted to investigate ultrasonic energy for reducing near-wellbore formation damage caused by organic deposits and polymers. It is shown that mechanical agitation provided by the acoustic waves re-suspends the paraffin and restores the effective permeability of the core to its undamaged condition. The depth of treatment is approximately 12 to 15 cm. This suggests that an acoustic source with or without solvents may provide an effective method of removing paraffins from the wellbore and the near-wellbore region. Ultrasonics was not as effective at restoring permeability damage caused by polymers. Our results demonstrate that ultrasonic cleaning may be a viable method for cleaning the near-wellbore region when paraffin precipitation is a problem. The method would be particularly effective at treating long sections of pay where chemical methods may be too expensive.
Synthesizing Dispersant for MTC Design and Its Effect on Slurry Rheology
Authors: Hou Jirui , Liu Zhongchun 
Published: December 2007

Summary
The dispersant's synthesis and its effect on slurry rheology are the basis of mud to cement (MTC) technique application. In this article are two methods to synthesize the dispersant by using fractions of C9, which are byproducts of the Daqing ethene production unit. The dispersant's production cost is reduced. Experimental work verifies that material produced by the new process can be used in a MTC design. The effect of the amounts of the dispersant and mud used on the rheology of MTC slurry are studied and discussed. The results show that the thickening time of a MTC slurry is clearly extended by mixing in the dispersant, thus improving the mobility of the slurry. We find that there is a low mobility or high consistency region when a MTC slurry is initially prepared. The appropriate measures for improving the quality of the MTC slurry are provided in this article. Moreover, the rheology of a MTC slurry is studied. We find that the Herschel-Bulkley model is the most accurate for describing the rheological properties of a MTC slurry. Last, the application of MTC technology in the Changqing field is introduced.
Operational Procedures and Applications of a Wireline Formation Tester To Accurately Characterize the Gas Composition of Stacked Multiple Pools in the North Malay Basin
Authors: Baxter M. F. W. , Abdullah Zulkiflie , Pearson M. R. 
Published: December 2007

Summary
In this article we review the development of techniques to acquire reliable reservoir gas samples using a wireline formation tester in the Malaysia-Thailand Joint Development Area. This region is characterized by gas accumulations comprised of multiple stacked separate pools where reservoir conditions are often considered hostile for wireline logging operations. In the article we use data from the 16-well exploration and appraisal program, during which 1968 pre-tests and 124 samples were successfully acquired, to compare the quality of gas samples from a wireline formation tester with those obtained from drillstem tests in the same zones.
Estimation of Turbulence Coefficient Based on Field Observations
Authors: Kelkar M. G. 
Published: December 2007

Summary
Isochronal testing is commonly used to evaluate the performance of gas wells. This paper proposes a new technique to estimate the value of the turbulence coefficient based on isochronal tests. The proposed method is easy to apply and evaluate. Further, the method also provides a value of bg under stabilized conditions which can be used to predict the performance of gas wells under stabilized conditions.
The proposed method is validated using field data under a variety of operating conditions. The values of the turbulence coefficient based on the field data can differ significantly compared to the literature correlations. This further shows the importance of obtaining appropriate reservoir parameters based on the field rather than the laboratory data.
Modeling Relative Permeability Effects in Gas-Condensate Reservoirs With a New Trapping Model
Authors: Pope G. A. , Wu W. , Narayanaswamy G. , Delshad M. , Sharma M. M. , Wang P. 
Published: December 2007

SummaryMany gas-condensate wells show a significant decrease in productivity once the pressure falls below the dew point pressure. A widely accepted cause of this decrease in productivity index is the decrease in the gas relative permeability due to a buildup of condensate in the near wellbore region. Predictions of well inflow performance require accurate models for the gas relative permeability. Since these relative permeabilities depend on fluid composition and pressure as well as on condensate and water saturations, a model is essential for both interpretation of laboratory data and for predictive field simulations as illustrated in this article.
Integration of Discrete Feature Network Methods With Conventional Simulator Approaches
Authors: Dershowitz Bill , LaPointe Paul , Eiben Thorsten , Wei Lingli 
Published: December 2007

Summary
The discrete feature network (DFN) approach offers many key advantages over conventional dual porosity (DP) approaches, particularly when issues of connectivity dominate recovery and reservoir stimulation in fractured and heterogeneous reservoirs. DP models have been developed for complex multiphase and thermal effects, and have been implemented for basin scale modeling. However, DP models address only the dual porosity nature of fractured reservoirs, generally simplifying connectivity and scale-dependent heterogeneity issues which are modeled efficiently and more accurately by the DFN approach.
This paper describes the development of techniques to integrate DFN and DP approaches. These techniques allow the analyst to maintain many of the advantages of the DP simulator approach without losing the realism of complex fracture system geometry and connectivity, as captured by DFN models.
The techniques described are currently used within a DOE funded research project for linking a DFN and a DP thermal simulation model for the Yates field, Texas. The paper describes some of the geological and engineering aspects of the Yates field and gives two examples of how DP parameters for the thermal simulation can be derived using DFN modeling techniques.
Relative Permeability at Near-Critical Conditions
Authors: Blom S. M. P. , Hagoort Jacques , Soetekouw D. P. N. 
Published: December 2007

SummaryWe have measured a series of two-phase drainage relative permeability curves at near-critical conditions by means of the displacement method. As a fluid system we have used the model system methanol/n-hexane that exhibits a critical point at ambient conditions. In the measurements we have varied the interfacial tension and the flow rate.Our results show a clear trend from immiscible relative permeability functions to miscible relative permeability lines with decreasing interfacial tension and increasing superficial velocity. The relative permeability measurements show that the controlling parameter is the ratio of viscous to capillary forces on a pore scale, denoted by the capillary number Nc=k‖∇Φ‖/ϕσ.To demonstrate the significance of using the proper relative permeability functions, we have calculated the well impairment due to liquid drop-out in a model gas condensate reservoir, for four different rock types showing four different relations between relative permeability and the capillary number. The calculations show that near-miscible relative permeability functions come into play in the vicinity of the well bore. This is contrary to what happens if the relative permeability would be a function of interfacial tension alone. In addition, the results show that well impairment by condensate drop-out may be significantly overestimated if the dependence of relative permeability on the capillary number is ignored.
New Empirical Correlation To Predict Apparent Viscosity of Borate-Crosslinked Guar Gel in Fractures
Authors: Goel Naval , Shah S. N. , Asadi Mahmoud 
Published: December 2007

Summary
Successful design and completion of hydraulic fracturing treatments depend on accurate estimation of fracturing fluid viscosity. This requires better knowledge of the fluid viscosity under in situ conditions. The viscosity estimation is even more important for borate-crosslinked guar gel because the gel behavior depends on temperature, wellbore shear pre-conditioning, fracture shear rate, and fluid pH. These factors require that the fluid characterization be performed under representative field conditions. Borate-crosslinked gel rheology is currently characterized in the laboratory and there is no theoretical correlation available to describe the gel rheology as a function of its dependent properties. The present study describes a correlation that is developed from data gathered by utilizing a field-scale fracture simulator and is based on the method of reduced variables. The study also extends the method to include the effect of shear history on the rheology of guar crosslinked with borate ions.
The correlation relates the apparent viscosity of the crosslinked guar to the fluid temperature, shear history, and shear rate. It is presented in a simple equation, which can be incorporated into fracturing software. The present study also provides master curves of the reduced apparent viscosity-shear rate for the borate-crosslinked guar at three pH values.
High-Silica Waters in Steamflood Operations
Authors: Bowman R. W. , Gramms L. C. , Craycraft R. R. 
Published: December 2007

Summary
Most steamflood operations recycling water will experience silica scales at some location in the field operation. It is usually noticed in the steam generators or heat recovery steam generators (HRSG) used for cogeneration. Whether fresh water or recycled water is used, the hot water, high pH portion of the steam will affect the steam injection wellbore. Silica scaling in the formation around production wells, in the screen of the production wells, and in the pump in the production wells are also noticed due to flashing and deposits of silicates.
Some of the silica scales can be controlled, some are beneficial, and some are very costly and difficult or impossible to control. In the formation the silica is in equilibrium with quartz so quartz solubility applies, while the more soluble amorphous silica solubility controls when not in contract with quartz rocks.
Commercial Deployment of Low-Dosage Hydrate Inhibitors in a Southern North Sea 69 km Wet-Gas Subsea Pipeline
Authors: Argo C. B. , Blain R. A. , Osborne C. G. , Priestley I. D. 
Published: December 2007

Summary
Threshold hydrate inhibitor (THI) has been successfully commercially deployed at a low-dose rate in a wet-gas pipeline connecting the Hyde-West Sole gas fields to the onshore Easington gas terminal. These gas fields are BP Amoco operated assets and are located in the U.K. sector of the southern North Sea, approximately 70 km offshore of the Easington gas terminal. Three gas platforms: Hyde, West Sole Charlie, and West Sole Bravo, are connected to a common 24-in.-diam flowline to shore and typical gas production lies in the range 50-180 mmscf/d (million standard cubic feet per day). The three platforms were sequentially converted from glycol to the new THI reagent. During the changeover period to THI reagent the pipeline operated a mixed system containing both THI reagent and glycol. As of 31 October 1996, the THI reagent has been deployed for 14 weeks. In the last three week period glycol content of the produced water arriving at the onshore terminal has been at a low level, typically, &lt;0.5 wt%.
Determination of the Viscosity-Temperature Relationship for Crude Oils With the Ultra-Viscoson
Authors: Howell James N. , Jessen F.W. 
Published: December 2007

Introduction
The determination of cloud points has to date been limited to rather transparent oils, visual observation of the formation of a solid phase being the criterion for the standard ASTM D 97-47 method.
The need for a quick and simple method for determining cloud points under dynamic conditions for opaque crude oils became necessary in a study of fundamental aspects of paraffin deposition from crude oils.

Previous Work
The determination of cloud points in opaque oils by viscosity temperature curves is fairly new, Young described a method employing the capillary tube principle. No information exists relative to the determination of cloud points of crude or refined oils under dynamic conditions.
Shock noticed that deposition of paraffin from crude oils took place at temperatures at or below the temperature at which a sharp inflection point occurred in the viscosity-temperature curve. This observation indicates a possible correlation between this temperature and the cloud point of the crude oil.
Reistle and Vietti have reported that when crude oils containing small amounts of asphaltic materials were heated to temperatures sufficiently high to solubilize these materials and immediately cooled the pour point of the crude oil was lowered as much as 70°F, Sachanen ascribes this effect to the action of colloidal asphaltenes in preventing the formation of the crystalline structure necessary to maintain the oil in a rigid state. At high temperatures, asphaltenes are peptized, and the paraffin crystals formed at these temperatures adsorb the colloidal asphaltenes on their surface thereby hindering further growth of the crystals. Reistle found, however, that such heating and cooling of crude oils had no effect upon the cloud points. This latter work dealt with a crude oil of fixed composition, and the question immediately arises as to the effect of varying the concentration of asphaltic materials on the cloud point.
Method for Delumping the Results of Compositional Reservoir Simulation
Authors: Leibovici C. F. , Barker J. W. , Waché David 
Published: December 2007

Summary
A new method for delumping the results of a compositional reservoir simulation is presented. The method is based on a previously published algorithm for delumping the results of a single flash calculation. Results are presented for two cases: depletion of a volatile oil reservoir and depletion with lean gas reinjection. The compositions obtained by delumping the results of a 7-component reservoir simulation are compared with those obtained from a 16-component reservoir simulation. If there are no binary interaction coefficients, the agreement is almost exact, and the delumping takes only a fraction of the computation time of the 16-component simulation. When nonzero binary interaction coefficients are introduced, the accuracy of the method is slightly reduced.
Slickline Power Unit on Coiled Tubing Provides Innovative Solution for Setting a Nippleless Lock in a Multilateral Completion
Authors: Hall J. B. , Wijngaards B. M. 
Published: December 2007

Summary
In the procedure most often used for drilling laterals from horizontal completions, a retrievable bridge plug is set in the casing. The bridge plug serves as the base for orienting and setting the whipstock used to drill the window in the casing so that the drilling of the lateral section can be initiated.
In monobore completions, operators can drill lateral sections through the tubing, and if coiled tubing drilling technology is used, this procedure can often be performed without killing the well and pulling the in-place completion. Drilling the horizontal lateral with the well flowing offers the advantages of efficient removal of the cuttings and reduced formation permeability impairment.
The retrievable bridge plug commonly used when being set with coiled tubing is the inflatable bridge plug. This plug can be run through most tubing restrictions and the element inflated to create the seal against the casing wall. If, however, casing damage or other well conditions prevent the inflatable bridge plug from being set, the operator may be left with few viable options for completing the drilling program.
This article will discuss such a case. In this scenario, repeated attempts to set an inflatable bridge plug failed during the opera-tor's drilling program. To provide a solution, a slickline running tool and nippleless lock mandrel were adapted for use with coiled tubing. Combining the slickline running tool and lock mandrel with coiled tubing had never before been attempted. In addition to providing a cost-efficient, innovative solution for a difficult service problem, the capabilities gained by combining these technologies show promise of enlarging the scope of viable alternatives for other service needs.
Revealing the Petrophysical Properties of a Thin-Bedded Rock in a Norwegian Sea Reservoir With Logs, Core, and Miniperm Data
Authors: Flølo L. H. , Kjærefjord J. M. , Arnesen D. M. , Menard W. P. , Weissenburger K. W. 
Published: December 2007

Summary
An unconventional thin-bed analysis based on logs, core, and miniperm data was needed to calculate the petrophysical properties of a reservoir under development in the Norwegian Sea. More than half of the reservoir section under investigation is composed of heterolithic facies: thinly interbedded sandstone and mudstone layers from one to several centimeters in thickness and of variable quality. By using miniperm measurements with 1-cm spacing on slabbed core, it was possible to resolve the properties of the rock far below the vertical resolution of conventional wireline logs and relate them to the bulk log measurements.
Sand Production on Water Injectors: How Bad Can It Get?
Authors: Santarelli F. J. , Skomedal Eiliv , Markestad Per , Berge H. I. , Nasvig Hâvard 
Published: December 2007

SummaryIn this paper we present a field case based upon a reservoir operated by Statoil in the Norwegian Sea. The case concerns a series of water injectors-i.e., both subsea and platform-that underwent extreme losses of injectivity over short periods of time. When worked over, the wells showed extreme amounts of sand fill that sometimes were several hundreds of meters above the top perforation. The link between well shut-ins and injectivity losses was clear right from the onset of the study.The life of the injectors is thoroughly reviewed and the reasons for the injectivity losses are established.First, it is shown that even under no flow conditions corresponding to shut-in periods, the rock around the wells is too weak to sustain the stresses and fails. Second, it is established that, because of permeability heterogeneity, the wells crossflow during shut-in periods, hence allowing sand to be produced in front of the perforated interval. Third, it is shown that under routine operation conditions the particles produced in front of the perforated intervals are not able to settle in the rathole before injection restarts and hence plug the perforation tunnel upon injection restart. Finally, it is demonstrated that, during a standard shut-in, pressure waves as large as 80 bar are generated because of the so-called water hammer effect that hits the formations as a seismic wave would do. As a consequence, the formation already weakened by sand production undergoes liquefaction that triggers large amounts of sand to be released in the well, thus killing totally its injectivity.Finally, we present how the operating conditions of the wells were successfully changed to avoid repetition of the problems experienced previously.
A New Design of Steady-State Type Experiments for Simultaneous Estimation of Two-Phase Flow Functions
Authors: Urkedal H. , Ebeltoft E. , Nordtvedt J. E. , Watson A. T. 
Published: December 2007

Summary
We have developed a new design of steady-state type experiments for simultaneous estimation of relative permeability and capillary pressure functions (collectively called multiphase flow functions) from measured pressure-drop and production data. The multiphase flow functions are represented by B-splines to ensure a flexible representation, and the coefficients in the representation are determined using a regression-based approach. The methodology is demonstrated using synthetic data. Further, we show that both relative permeability and capillary pressure functions can be estimated, and we were able to reconcile all pressure-drop and production data from the steady-state type experiment conducted. An analysis of the accuracy of the estimated functions showed that they were accurately determined over a large saturation interval.
Identification and Exploitation of a High-Producing Field Extension With Integrated Reservoir Analysis
Authors: Waite M. W. , Weston J. R. , Davis D. W. , Pearn C. J. 
Published: December 2007

Summary
The Wafra field is located in the partitioned neutral zone between Kuwait and Saudi Arabia. The field produces oil from the Ratawi oolite reservoir, which has been under production since 1956. Barriers to fluid movement have severely restricted aquifer support to the overlying carbonate grainstone reservoir, leading to production-induced pressure depletion and low recovery rates. Creative integration of three-dimensional seismic aspects, well log stratigraphy, and engineering analysis revealed an unexploited reservoir extension that is more open to aquifer pressure support. Wells drilled along this extension are expected to yield higher initial production rates and longer sustained production. The model was used to drill two successful step-out wells that have increased field production by over 12,000 BOPD. Eight of ten additional wells have now been drilled as a follow-up to this success. This paper reviews the case history with a focus on the multidisciplinary integration that led to opportunity identification and exploitation.