bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Silicate-Based Drilling Fluids To Mitigate Metal Corrosion
Authors: McDonald M. , Barr K. , Dubberley S. R. , Wadsworth G. 
Published: December 2007

Abstract
Since the re-introduction of silicate-based drilling fluids in the mid-1990's, there have been numerous papers written on the inhibitive and environmental properties of sodium and potassium silicate. While it is generally accepted that potassium or sodium based silicate drilling fluids will help mitigate metal corrosion, there appears to be very little written on the subject. With increasing steel prices and competition for drill pipe, operators are becoming more aware of the cost associated with metal corrosion.
This paper discusses the chemistry of sodium and potassium silicate as it relates to the protection of metals against corrosion. Aside from providing an alkaline environment, silicate is shown to deposit a protective film on various metal surfaces. Drill string corrosion coupons were used to gauge the amount of wear and corrosion while running potassium silicate-based drilling fluids in Western Canada. Gravimetric analysis confirmed that the rate of metal corrosion was minimal under a variety of drilling conditions.
Downhole Integrity Management in October Field, Gulf of Suez, Egypt
Authors: Ramadan Nasr , Rocha George , Michel Charlie , Hey Michael James 
Published: December 2007

Abstract
The paper discusses historical data related to downhole scaling, corrosion and surveillance methods to identify affected wells. Efforts to minimize production impact due to increased corrosion seen late in the field life along with longer term corrosion mitigation efforts are also reviewed. Examples of how tubing was originally protected by thin film scale accumulation and emulsion flow during early field life production are also presented. Increasing October's completion corrosion manageability is a key challenge facing the field. Addressing issues related to predicting future well failures and their associated production loss impact rig scheduling and procurement of expensive long-lead time completion material (Cr 13%).
The approved plan is to repair six wells per year over three years considering known well problems, remaining reserves, materials and rig availability. In early 2005, six well's were worked over and visual inspection of retrieved tubing showed an excellent match with caliper log data. The most severe corrosion is typically deep in the well and is related to high CO2 partial pressures. Corrosion risk to the casing has also been identified as potential issue and wall thickness assessments have been performed on some workovers. The paper reviews these items in greater detail and proposes forward plans for the remaining life of field.
Laboratory and Field Prediction of Sulfate Scaling Damage
Authors: Bedrikovetsky P. G. , Mackay E. , Monteiro R. P. , Gladstone P. M. , Rosário F. F. 
Published: December 2007

AbstractThe BaSO4 scaling is a chronicle disaster in waterflood projects with incompatible injected and formation waters. This is usually due to precipitation of barium sulphate from the mixture of both waters and consequent permeability reduction resulting in well productivity decrease.The sulphate scaling damage system contains two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient reflecting permeability decrease due to salt precipitation.Previous work has derived analytical-model-based method for determination of kinetics coefficient from laboratory coreflood on quasi steady state commingled flow of injected and formation waters. The current study extends the method and derives formulae for calculation of formation damage coefficient from pressure drop measurements during coreflood.The proposed method can be extended for axi-symmetric flow around the well allowing calculation of both sulphate scaling damage coefficients from field data on barium concentration in produced water and well productivity decline.We treat several laboratory test data and field data, and obtain values of two sulphate scaling damage parameters. The values of kinetics and formation damage coefficients as obtained from either laboratory or field data vary in the same range intervals. It validates the proposed mathematical model for sulphate scaling damage and the analytical-model-based method "from lab to wells".
Subsidence-Induced Casing Dogleg (SICDog) Remediation With an Innovative Hybrid Milling System
Authors: Winston D. S. , Sullivan M. , Finch R. C. , Fulcher R. 
Published: December 2007

Abstract
Subsidence Induced Casing Doglegs (SICDogs) occur in many oil reservoirs worldwide. Doglegging, at a minimum, leads to reduced mean time between failures of rod pumped wells. SICDog remediation techniques in the past have had limited success and are relatively expensive procedures. Most of these techniques have used various rotating mill assemblies and different strengths, sizes and connections of drill pipe. Some techniques have been extreme, such as destroying the dogleg with explosives. A multiphase, risk-sharing, team effort over four years between Aera Energy LLC and Weatherford International Ltd led to the development by Weatherford of a hybrid broaching/milling tool. This hybrid milling system reliably and quickly remediates multiple doglegs in a single well bore. Seven Diatomite reservoir producers in the South Belridge Oil Field, Kern County, California were repaired and successfully returned to production in the latest four well phase. The work was routine in nature, requiring no special or extraordinary services. In this paper, we will discuss the geometry of SICDogs and the challenges they pose to rotational milling. Other topics will include the evolution of the hybrid tool from experiences in this and other projects, operational concerns such as well control and repair options of the remediated SICDog. Lessons learned during the evolution of this technique will be discussed at length.
Real-Time Monitoring of Acid Stimulation Utilizing a Fiber-Optic DTS System
Authors: Clanton R. W. , Haney J. A. , Pruett R. , Wahl C. L. , Goiffon J. J. , Gualtieri D. 
Published: December 2007

AbstractThis paper discusses a unique system that combines a fiber-optic distributed temperature system (DTS) to measure the distributed temperature across the entire wellbore and a molecular telemetry transmission system that provides a single-point determination of bottomhole pressure. The system has been used to perform real-time downhole monitoring of multi-stage acid-stimulation treatments performed on wells that contain multiple non-isolated pay intervals. The fiber-optic for the DTS is contained inside a length of capillary tubing, which is placed concentrically inside a larger size capillary tubing. The created annulus between these two strings of capillary comprises the molecular transmission system for determining the bottomhole pressure.Real-time-distributed temperature data and single-point bottomhole pressure data are provided on location. In the case history presented, the temperature profile across the multiple pay intervals yielded valuable information for identifying which zones were "taking" the acid, allocating how much acid these zones were taking (relative to one another), and identifying the zones not taking acid. This allowed on-the-fly changes to be made on-site in real-time regarding the make-up of the acid treatment, the pumping rates, and when and where to apply diversion processes.This system enabled the operator to continuously monitor the wellbore temperature across the interval that was being stimulated as well as from a single-point bottomhole pressure below the lowest perforation. In this case, the system was deployed inside the work string used for the acid stimulation, but the system can also be permanently deployed.The nominal ratings for this monitoring system are 250°C and 10,000-psi. This allows the system to be applied in a large number of wells, either onshore or offshore. Furthermore, there are no downhole electronics and no moving parts, making the system extremely well suited for harsh environments.
Tahiti: Development Strategy Assessment Using Design of Experiments and Response Surface Methods
Authors: Carreras P. E. , Turner S. E. , Wilkinson G. T. 
Published: December 2007

AbstractTahiti field in deepwater Gulf of Mexico is a three-way anticlinal structure trapped against salt, with primary hydrocarbon-bearing turbidite sands ranging from 24,000 to 27,000 ft TVD. The discovery well was drilled in 2002, and two appraisal wells were drilled soon afterwards. Due to significant uncertainties remaining after appraisal, probabilistic methods were used to assess development alternatives.In this study the classical experimental design method was applied and reasonable P10, P50 and P90 reservoir simulation models were designed. Next, we looked upon the development plan by performing a second round of design of experiment runs with uncontrollable uncertainties and decisions as factors. The goal was to validate that the previously selected models reasonably represented P10, P50 and P90 oil recoveries and net present value after including decisions in the design. The validation worked out properly reinforcing the confidence in the model selection. Finally, the polynomial response models were used to explore multiple scenarios by varying decisions across the whole range of uncontrollable uncertainties.The proposed workflow enhances the use of experimental design by combining the technique with response surface methods and rational engineering judgment. The approach is recommended for the evaluation of greenfields when a new perspective of the economic analysis of project decisions is desired.
Analytical Model for Vertical Oil/Water Displacement Under Combined Viscous, Capillary, and Gravity Effects
Authors: Rosado-Vázquez F. J. , Rangel-German E. R. , Rodriguez-de la Garza F. 
Published: December 2007

Abstract
A mathematical model for water injection in vertical porous media initially saturated with oil and water is presented. The mathematical formulation takes the form of a nonlinear convection-diffusion equation. Its contribution comes from consideration of the three chief forces (viscous, capillary and gravity) in oil recovery processes. The model is general in that it can use any shape for relative permeability and capillary pressure functions, and it is developed to allow analysis of these forces individually or in a combined manner.
By using Corey-type functions for relative permeability, logarithmic functions for capillary pressure, and Peclet and Gravity dimensionless numbers, the flow equation is written in a dimensionless form.
In order to represent the physics of the oil-water displacement more accurately, variable saturation-dependent coefficients for the diffusive (capillary) and convection (viscous and gravity) terms were used. Thus, a nonlinear equation is obtained. A numerical model based on the finite-difference formulation with a fully implicit scheme was implemented to obtain the solution to this equation. The analytic solution for the diffusion-convection equation for the semi-infinite problem published elsewhere and the well-known Buckley-Leverett solution were used to validate the numerical algorithm.
The numerical model allows evaluation of the influence of each of these three forces on the magnitude and direction of the dimensionless water velocity. Water velocity is defined as the sum of the velocity contribution of each force (viscous, capillary and gravity). This model also helps determine favorable scenarios for each force. For instance, the analytic equation and the numerical results show the cases in which one force dominates the others, under given petrophysical and fluid properties and oil or water injection velocity.
Finally, by setting the proper boundary and initial conditions, this model can be used to simulate any displacement in which these three forces interact.
Improved Analytical Model and Experimentally Calibrated Studies of Steam Injection With Hydrocarbon Additives To Enhance Heavy-Oil Recovery
Authors: Simangunsong R. A. , Jaiswal N. J. , Mamora D. D. 
Published: December 2007

Abstract
Experimental, analytical and simulations studies have been conducted to investigate the use of propane and petroleum distillate as steam additives to enhance production to gain a better understanding of production mechanisms of 12°API and 2800 cp heavy oil from San Ardo field, California.
The experiments consist of injecting pure steam, steam- propane, and steam-petroleum distillate into a vertical cell containing a mixture of sand, water and San Ardo oil. The injection cell (68.58 cm long with an ID of 7.376 cm) is placed inside a vacuum jacket, set at the reservoir temperature of 53.3°C. Superheated steam at 230°C is injected at 5.5 ml/min (cold-water equivalent) simultaneously with propane or a petroleum distillate slug. The cell outlet pressure is maintained at 260 psig. Six runs were performed, two runs using pure steam, two steam-propane runs using 5:100 propane:steam mass ratio, and two steam-petroleum distillate runs using 5:100 petroleum distillate:steam mass ratio.
A simplified analytical model is developed to describe steam front advancement and oil production for the 1D displacement experiments. The model incorporates heat and material balance, fillup time and Darcy's law pertaining to the injection cell.
A simulation study was conducted using 1D 48 grid cell model. Satisfactory history matches of the experimental runs were obtained. The analytical and simulation model results are compared against the experimental data to verify the validity of the model.
The main findings of the research are as follows. First, experimental results indicate that compared to pure steam injection, oil production was accelerated by 30% for 5:100.propane:steam injection and 38% for 5:100 petroleum distillate:steam injection respectively. Second, steam injectivity with steam-propane and steam-petroleum distillate increases to 1.4 and 1.9 times respectively, compared with pure steam injection. Third, steam front advancement and oil production data are in good agreement with results based on the analytical and simulation model. The analytical and simulation models indicate that oil production acceleration observed is due to oil viscosity reduction resulting from the addition of propane and petroleum distillate to the steam.
An Evolution from Smart Wells to Smart Fields
Authors: van der Steen E. 
Published: December 2007

Abstract
This paper discusses the "evolution" from Smart Well installations to the delivery of a fully integrated "Smart Field". Capabilities were first developed and tested in nearby fields before being applied in the Champion West field. Results and issues with the component Projects are discussed. The creation of a "Smart Field team" with representation from Petroleum Engineering, Well Engineering, IT, Control and Automation, Data Management/Application, Facility Engineering and Production Engineering is seen as a key enabler for a successful Smart Field development.
Successful Control of High-Pressured Gas Well Using a Crosslinked Gel during Coiled-Tubing Fishing
Authors: Nwoke L. , Arukhe J. , Uchendu C. 
Published: December 2007

Abstract
Good well and reservoir management practices demand that new gas wells be tested to expected potentials at the onset of production and build up surveys carried out at specified intervals during the life of the well. This will help to determine the deliverability of the wells, obtain base reservoir parameters and for reservoir surveillance in monitoring depletion of gas reservoirs. It was in pursuit of the above data gathering that lead to the stalled Multi-rate Build Up survey resulting to stocked temperature and pressure memory gauges at RN-nipple.
The production capability of this well was estimated at 150 MMscf/d of gas. Following the installation of the memory gauges, Multi-rate and 10-hour Build-Up tests were conducted. During the retrieval of the BHP gauges, several incidents lead to three successive fishes getting stocked into the well bore. The Operator was faced with many challenges: ‘do nothing and produce the well in an unsafe manner at 50% potential’, ‘attempt a work over’ or ‘attempt a coiled tubing rigless intervention’, with each option having its attendant limitations.
During the planning stage of the remedial operation, success in retrieving the multiple fishes was identified to come from the ability to kill the high pressure gas well with a time dependent and acid degradable cross-linked gel system through a high rate bullhead pumping technique and appropriate wireline/coiled tubing fishing tools that will simultaneously locate the wire rope and grab it, minimizing run-time in costs effective manner. The kill fluid had low damage potential to the formation was capable of preventing the migration and fingering of formation gas to the surface throughout the fishing operation that lasted for approximately one month of 24-hour day. Key success was also identified to be the ability of coiled tubing to compress wire rope in bunches and exertion of extra over pull to aid in freeing the stuck fish.
At the end of the operation that lasted for one month with difficult challenges; the five (3+2) stuck fishes were successfully retrieved and pre-fishing conduit potential was retained, indicating that the cross-linked gel completely got degraded internally at the end of the fishing operation leaving the near wellbore region undamaged.
The gain from the operation includes leaving the formation in undamaged state after the operation, cost savings, high NPV and escaping from penalty for failing to meet gas contractual obligation if the well is produced at less than programmed production. Over $2.0 million was saved operationally with the choice of rigless activity when compared to other alternatives and the well is still producing satisfactorily after more than five years from the time of this activity.
This paper presents the engineering design, field application and learning from the fishing operations.
Three Dimensional Hybrid DD-FEM Model for Fully Coupled Reservoir Simulation
Authors: Yin S. , Dusseault M. B. , Rothenburg L. 
Published: December 2007

Abstract
In an infinite or semi infinite domain, a petroleum reservoir is seen as a displacement discontinuity; hence, an efficient displacement discontinuity method is used to calculate the stress and displacement changes around a petroleum reservoir. Based on the theory of poroelasticity, a 3-D finite element method is used to account for the local reservoir model. Coupling of the displacement discontinuity method and finite element method, a 3-D large-scale reservoir can be simulated to exist in a poroelastic infinite or semi-infinite domain. The model has been verified and the application is given. Results indicate that the complete overburden response has a significant impact on stress transfer during reservoir depletion.
Review of Issues Associated With Inhibition of Scale-Deposit-Covered Pipelines
Authors: Turgoose S. , Dicken G. E. , Palmer J. W. 
Published: December 2007

Abstract
As reservoirs mature, the amount of water produced increases and velocities reduce. Hence, there is a greater likelihood that deposits will collect at low points in a line. Also, in some instances, poor chemical management may lead to a build-up of scale deposits or corrosion products. All of these factors increase the risk of localised corrosion. In parallel with the above, there is a worldwide requirement to extend the life of ageing assets.
This paper reviews the issues associated with establishing adequate corrosion control in systems that contain significant amounts of deposit, be it sand, scale or corrosion products. Laboratory test data is used to illustrate the effects on corrosion inhibition and the possible consequences with respect to integrity management are highlighted.
Examples include: Inhibition of localised corrosion beneath scalesThe effect of sand beds on inhibitionThe influence of corrosion product films on inhibitor performance.
Novel test procedures are described and the results and conclusions will demonstrate the importance of actively addressing these issues in inhibitor selection programmes.
Factors Controlling the Membrane Efficiency of Shales When Interacting With Water-Based and Oil-Based Muds
Authors: Al-Bazali Talal M. , Zhang Jianguo , Chenevert Martin E. , Sharma Mukul M. 
Published: December 2007

Abstract
This paper presents a comprehensive set of experimental data for the membrane efficiency of four shales when interacting with different water-based and oil-based muds. Pressure transmission tests were used to measure the membrane efficiency using three different cations and two different anions at different concentrations (water activities).
It was found that the measured membrane efficiencies of shales when exposed to salt solutions were low, ranging from 0.18% to 4.23%. Useful correlations are presented between the membrane efficiency and other shale properties. Results suggest that the membrane efficiency of shales is directly proportional to the ratio of the cation exchange capacity and permeability of shales. Higher cation exchange capacities and lower permeabilities correlate very well with higher membrane efficiencies. Moreover, the ratio of the hydrated solute (ion) size to shale pore throat determines a shale's ability to restrict solutes from entering the pore space and controls its membrane efficiency. Cations and anions with large hydrated radii yielded higher membrane efficiencies, compared to ions with small hydrated diameters. Thus, the formulation of drilling fluids must take into account the types of cation and anion in the water-based fluid.
It was also found that the membrane efficiency of oil-based muds was high, however, these membrane efficiencies were not 100 % as postulated by many researchers.
The Drilling and Casing Running Enigma
Authors: Mason C. J. , Chen D. C. -K. 
Published: December 2007

Abstract
Running casing in high angle and extended-reach wells is often recognized as one of the most demanding of all well construction operations. In such wells, frictional drag and unexpected downhole mechanical resistance can exceed available surface slack-off weight. The ability to reliably predict casing running performance will significantly help to reduce costs in challenging wells. Interestingly, a complex and often subtle relationship exists between a drilled wellbore and the subsequent casing run. This relationship is sometimes predictable and at other times surprisingly different. A key to resolving this enigma lies in understanding the many factors, such as wellbore quality, that influence the outcome of casing running operations. The paper reviews a number of topics that are considered key to understanding the relationship between drilling and casing running. Various results are illustrated using case studies from field operations.