bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanistic Understanding of Rock/Phosphonate Interactions and the Effect of Metal Ions on Inhibitor Retention
Authors: Tomson M. B. , Kan A. T. , Fu G. , Shen D. , Nasr-El-Din H. A. , Al-Saiari H. , Al-Thubaiti M. 
Published: December 2007

Abstract
This paper discusses the effects of Ca2+, Mg2+, and Fe2+ on inhibitor retention and release. Better understanding of phosphonate reactions during inhibitor squeeze treatments has direct implication on how to design and improve scale inhibitor squeeze treatments for optimum scale control. Putting various amounts of metal ions in the inhibitor pill adds another degree of freedom in squeeze design, especially in controlling return concentrations and squeeze life.
Phosphonate reactions during squeeze treatments involve a series of self-regulating reactions with calcite and other minerals. However, excess calcite does not improve the retention of phosphonate due to the surface poisoning effect of Ca2+. The squeeze can be designed so that maximum squeeze life is achieved by forming a low solubility phase in the formation. Addition of Ca2+, Mg2+, and Fe2+ in the pill solution at 0.1 to 1 molar ratios significantly improves the retention of phosphonate. Alternatively, these metal ions can be dissolved from the formation while an acidic inhibitor pill is in contact with the formation minerals. Both BHPMP and DTPMP returns were significantly extended by the addition of metal ions, e.g. Ca2+ and Fe2+. The addition of Mg2+ may increase the long-term return concentration, which is important for some wells where a higher inhibitor return concentration is needed.
The laboratory squeeze simulations were compared to two field return data obtained from squeeze treatments performed on two wells located in a sandstone reservoir in Saudi Arabia. The sandstone formation contains significant amounts of ironbearing minerals.
Scale Inhibitor Core Floods in Carbonate Cores: Chemical Interactions and Modelling
Authors: Baraka-Lokmane S. , Sorbie K. S. 
Published: December 2007

Abstract
In previous work (SPE 87447), the effect of pH on phosphonate/carbonate interaction was studied by performing variable pH core floods in short outcrop carbonate cores. Effluent concentrations of scale inhibitor (DETPMP), lithium tracer, calcium and magnesium were measured, as were the corresponding pH profiles. Such detailed sets of measurements are required to interpret the inhibitor/carbonate interaction mechanisms. This previous study showed that carbonate dissolution was evident in all core floods and on how this depended on pH. It also indicated where simple adsorption isotherms could describe this accurately and where this was not the case. Recently, we have performed additional core floods using carbonate core from a second block of this outcrop chalk using DETPMP scale inhibitor slugs at various concentrations and pH values. These results significantly extend previous work and are presented under the following two headings:
Scale inhibitor/carbonate/pH interactions in short cores + modelling: Simple flooding cycles are described on the propagation of (Li traced) slugs of pH 6, 4, and 2 (no scale inhibitor) travelling through the carbonate core in order to study the behaviour of calcium, magnesium and effluent pH for various injected brine pH conditions. These results have been modelled and explained using the MultiScale software.
"Contained" scale inhibitor floods in long (12") carbonate cores: Contrasting floods using long (12") carbonate cores have been performed where &lt;1 PV of DETPMP is injected at the inlet and then back produced. In these floods, the core is never fully saturated and these floods are referred to as "contained" core floods [1]. Very extensive data on SI, cation (Ca, Mg and Li) and pH effluents are collected. These observations lead us to a number of conclusions on the factors that must be included in a full carbonate model. In particular, our experimental results – along with some simple modeling – greatly clarify the role of both calcium and magnesium in the mechanism SI retention in carbonate systems.
Novel CO2-Emulsified Viscoelastic Surfactant Fracturing Fluid System Enables Commercial Production From Bypassed Pay in the Olmos Formation of South Texas
Authors: Semmelbeck M. E. , Deupree W. E. , von Plonski J. K. , Mueller F. A. , Chen Y. , Lewis J. W. , Keto L. K. , Fairhurst D. L. , Pope T. L. 
Published: December 2007

Abstract
A novel carbon dioxide- (CO2-) emulsified viscoelastic surfactant (VES) fluid system has recently been used to improve the Olmos production in the Caterina SW field in Texas. The reservoir is characterized by thin streaks of pay with potential water production in close proximity. Due to the low permeability and formation rock properties, CO2-type fracture fluids have proven to be more effective. VES-CO2 was selected as the fracturing fluid because of its higher retained proppant pack permeability and controllable rheological behavior. These unique fluid characteristics resulted in a high-conductivity fracture and a geometry that stayed out of the water-bearing zones. The outcome from 11 treatments resulted in an average production of &gt; 430 Mscf/D and 82 BOPD in zones that were previously bypassed. The successful field applications of this new fluid system highlight the versatility of VES surfactant fluids in terms of rheological property and adaptability. Specific performance requirements can be met through modifying the functionalities of the surfactants, namely, utilizing surfactants with different functions to emulsify super-critical CO2 and still maintain all of the attributes normally associated with VES systems. VES fracturing fluid systems exhibit lower friction pressure, superior proppant transport, higher fracture conductivity and longer effective fracture half-length than conventional systems by completely eliminating polymer. Coupling the benefits of polymer-free VES fluid with a CO2-emulsified system further enhances cleanup of depleted reservoirs, extends the application to water-sensitive formations, and maintains reservoir gas saturation to prevent any potential water blocks.
Improving the Gas and Condensate Relative Permeability Using Chemical Treatments
Authors: Kumar V. , Pope G. A. , Sharma M. M. 
Published: December 2007

Abstract
Production from gas-condensate reservoirs having a bottom hole flowing pressure below the dewpoint pressure results in an accumulation of condensate near the wells causing a large decrease in both the gas and condensate relative permeability. Several methods such as hydraulic fracturing and solvents have been proposed to restore production rates but all of these methods have limitations or they are only effective for short periods of time. We have evaluated new surfactants using a methanol-water mixture as the solvent to treat cores under reservoir conditions. The surfactants have been tested under reservoir conditions using a variety of cores and found to be promising since they significantly increased the steady state relative permeability. Experiments were performed to evaluate the effectiveness of these surfactants at high temperature and high gas flow rates over a range of capillary numbers on the order of those near production wells. The productivity index for sandstone cores was improved by a factor of 2 to 3 for temperatures over the temperature range of 145 to 275 °F for the Novec FC 4430 polymeric surfactant in the methanol-water mixture. These treatments have the potential to greatly increase production at low cost since only the near well region of the reservoir blocked by the condensate needs to be treated.
Simulation Study on Injection of CO2-Microemulsion for Methane Recovery From Gas-Hydrate Reservoirs
Authors: Phale H. A. , Zhu T. , White M. D. , McGrail B. P. 
Published: December 2007

Abstract
Gas-hydrates are crystalline substances composed of water and gas, mainly methane, in which a solid water lattice accommodates gas molecules in a cage like structure. Large methane-gas hydrate reservoirs have been found on the North Slope of Alaska that can be exploited as a future energy source. Depressurization, thermal stimulation, and inhibitor injection are the methods being evaluated for commercial production of natural gas from hydrate-bearing geologic formations.
An alternative method of gas hydrate production using CO2 is under investigation. This process conducts injection of CO2 in the form of microemulsion. This concept has several attractive features: 1) CO2 is thermodynamically favored over CH4 in hydrate, 2) the heat released by formation of CO2 hydrate is 20% greater than the heat needed for dissociation of CH4 hydrate, 3) refilling pore space with CO2 hydrate is expected to maintain mechanical stability of the hydrate-bearing formations during production, and 4) the process is environmental friendly, removing CO2 from the atmosphere while simultaneously producing clean-burning natural gas. This study focuses on the evaluation of a set of optimum parameters for methane recovery with simultaneous CO2 sequestration using the STOMP-HYD simulator. Series of simulations are being carried out to verify the effect of pressure, temperature, CO2-microemulsion injection rate, and the concentration of injected CO2-microemulsion on methane hydrate dissociation. Preliminary, 1-D simulations show that injection of CO2-microemulsion produces considerably more amount of methane than warm water injection alone. These results have also demonstrated that injection of liquid CO2-microemulsion helps in early and significant methane production as compared to the injection of vapor CO2-microemulsion. Initial modeling work supports the novel idea of using CO2-microemulsion for Enhanced Gas Hydrate Recovery.
A Study of Fracture Initiation Pressures in Cemented Cased-Hole Wells Without Perforations
Authors: Rytlewski G. L. , Cook J. M. 
Published: December 2007

Abstract
A new method of completing multiple-layer tight gas wells is being investigated. The main concept is to place sliding sleeve valves in the casing string and complete the well with normal cementing operations. The sliding sleeves would then be opened one at a time to fracture layers independently without perforating. The possibility of high fracture initiation pressures is identified as the main risk with this approach.
This paper will discuss the theoretical and experimental study that was conducted to assess the viability of the cemented sliding sleeve concept by attempting to minimize and predict fracture initiation pressures.
Finite Element Analysis (FEA) was conducted to estimate the stresses in the cement and formation near the wellbore with sliding sleeve. FEA was used to adjust valve parameters that increased tensile stress in the cement and formation. Unstressed cement tests were then conducted on a variety of sliding sleeve valve shapes to verify the FEA study and to select the best valve shape.
Openhole and perforated casing fracture initiation pressures were calculated as a function of rock properties and far field stresses on the rock. An openhole condition was considered the best approximation to the opened sliding sleeve valve in regards to fracture initiation.
Full-scale stress frame tests were conducted using sandstone blocks with far field stress applied. The base case was set up using 4-1/2-in diameter casing cemented in one block and then perforated in the preferred fracture plane. Another sandstone block had a sliding sleeve valve cemented in place. Water was used to fracture these blocks and the fracture initiation pressures were measured. Good agreement between predictions and measurements was obtained, and the results indicated that high fracture initiation pressure is unlikely to be an issue with this completion method.
Well Testing of Tight Gas Reservoirs
Authors: Garcia J. P. , Pooladi-Darvish M. , Brunner F. , Santo M. , Mattar L. 
Published: December 2007

Abstract
Advances in technology, strong energy prices and declining reserves in conventional gas reservoirs are encouraging oil and gas companies to consider the feasibility of exploiting large reserves trapped in tight (low permeability) gas reservoirs.
Conventional well tests conducted on these low permeability gas formations, generally result in poor estimates of key reservoir parameters such as: initial reservoir pressure, permeability, effective fracture length, fracture conductivity, and deliverability potential.
The objective of this paper is to review the different types of tests that are particularly applicable to tight gas formations, discuss why the traditional methods of testing and analysis rarely succeed, and identify appropriate test and analysis procedures for tight gas reservoirs.
We will consider short-term tests where the primary objective is to obtain the initial reservoir pressure, with a secondary objective of determining permeability and skin. Perforation Inflow Tests, Fracture-Calibration Tests, and Formation Flow Tests will be considered. The applicability of these tests will be shown using synthetic and actual field cases.
Constant-Rate Drawdown Solutions Derived for Multiple Arbitrarily Oriented Uniform-Flux, Infinite-Conductivity, or Finite-Conductivity Fractures in an Infinite-Slab Reservoir
Authors: Craig D. P. , Blasingame T. A. 
Published: December 2007

Abstract
A new analytical pressure transient solution (constant rate) for a well containing multiple arbitrarily-oriented uniform-flux, infinite-conductivity, or finite-conductivity fractures in an infinite-slab reservoir is presented. The multiple-fracture solution is derived using a new uniform-flux solution for a single arbitrarily-oriented fracture in an anisotropic reservoir. The variables in this solution are: fracture half-length, fracture conductivity, and fracture angle of rotation for each fracture relative to the primary fracture. Example constant-rate type curves are provided for two intersecting fractures – cruciform or oblique – and three intersecting fractures – trifracture.
BHA and Drillstring Modeling Maximizes Drilling Performance In Lateral Wells of Barnett Shale Gas Field of N. Texas
Authors: Janwadkar S. S. , Fortenberry D. G. , Roberts G. K. , Kramer M. , Trichel D. K. , Rogers T. , Privott S. A. , Welch B. , Isbell M. R. 
Published: December 2007

Abstract
The Barnett Shale field of North Texas is one of the most prolific and fastest growing natural gas fields in North America with a multi-trillion cubic feet equivalent upside potential. However, the area presents numerous drilling challenges. In the vertical section, roller cone bits had unacceptable low penetration rates while PDC bits suffered premature damage. High torque and drag along with low penetration rates hampered drilling the curve and lateral sections. To address these challenges, a detailed engineering analysis was performed utilizing sophisticated BHA and drill string modeling software. Engineers studied offset wells and drillstring modeling including buckling load analysis, critical speed analysis, and torque and drag analysis.
As a result of the study, engineers determined that bit whirl and stick-slip were resulting in premature bit damage and reduced ROP while drillstring buckling resulted in inefficient transfer of weight on bit. Modeling helped design a BHA that mitigated buckling while optimized drilling parameters avoided critical speeds. The improvements resulted in 42% to 121% higher penetration rates with minimal damage to the PDC bits. The 83/4" vertical section was drilled in one PDC run in 60 out of 104 wells resulting in significant reduction in rotating hours and average cost per foot. The new BHA reduced drillstring buckling and significantly reduced torque and drag while drilling the curve and lateral sections.
The authors will describe the significance of applying principles of buckling load and torque and drag analysis; to design technically sound BHA's. They will also discuss how to utilize drillstring dynamics to avoid critical speeds.
Dynamic Modeling of Partial Liquid Lift for Stripper Gas Wells
Authors: Rastegar Moghadam R. , Khoshnevis B. , Ershaghi I. 
Published: December 2007

Abstract
This paper presents the results of a dynamic modeling approach for prediction of the critical rate to unload stripper gas wells. Methodologies in the literature such as the ones by Turner et al1and Coleman et al2 predict critical gas rates by using force balances based on bulk properties of the liquid and gas column. Using a one-dimensional modeling of two phase flow in a vertical column, we are able to incorporate the phase behavioral effects caused by temperature and pressure changes affecting fluid density and localized conditions of liquid droplets demonstrating a more accurate way to predict critical gas rates.
The dynamic prediction model allows incorporation of the formation depth and pressure, temperature gradients and tubing size. Gas composition ranges from dry gas to rich gas with potential for condensate formation. The model allows mapping and tracking the phase behavior conditions after flow stoppage under the condition of low gas rate and predicts the energy requirement to partially lighten the liquid column and resuming gas flow.
Reducing Electric Pumping Consumption in Mature Fields: Case Studies
Authors: Reedy M. A. , Ershaghi I. 
Published: December 2007

Abstract
There are about 640,000 pumping units nationwide consuming over 50,383 gigawatt-hours (GWh) annually. Based on a study conducted for the California Energy Commission1, more than 45% of these pumping units in California may be operating so inefficiently that their electric power consumption is often 8-10 times more than an efficient pumping system. Other studies and papers have suggested that energy saving projects are viable and economically attractive. However, operators are not actively pursuing these types of projects. The PTTC "PUMP" sponsored by the U S Department of Energy identified several reasons why operators hesitate to take advantage of technologies to improve efficiency and reduce operation cost. For many operators implementing corrective measures involves uncertainty, a misunderstanding or a lack of trust about new technologies. Operators resist change when they do not understand its implications and perceive that it might cost them much more than they gain. Wells operated inefficiently may prematurely experience their economic limit further affecting our domestic production. Continued long-term pumping inefficiencies have negative implications for the operator, for the fields and for the nation's power grid. This paper includes specific information on actual energy reduction projects installed by small producers in California including production impacts, project costs, energy savings, and project economics.
Scale-Inhibitor Testing for Multiphase Pipelines in a Subsea-to-Shore Development With a Closed MEG-Loop System
Authors: Halvorsen E. N. , Halvorsen A. M. K. , Ramstad K. , Tydal T. , Biørnstad C. 
Published: December 2007

Abstract
The sub sea development of the Ormen Lange gas field located in the Norwegian Sea will use MEG (mono-ethyleneglycol) for hydrate inhibition. Gas, condensate and MEG + water will be transported through a multiphase carbon steel pipeline to the onshore process plant at Nyhamna located on the west coast of Norway.
pH adjustment and film forming corrosion inhibitor will be used to control the corrosion rate in the pipeline. Although the corrosion rate is low during production, iron will be produced due to corrosion and follow the MEG/water phase. Most of the iron will be removed as iron carbonate particles during the MEG regeneration process but about 10ppm iron as particles and ions is expected to circulate in the MEG-loop.
Production of formation water will result in carbonate scaling when pH stabilised MEG is used as corrosion control unless a scale inhibitor is used. Three commercial scale inhibitors have been tested for this system. Tests have been performed without iron, with iron ions and with iron carbonate particles present. The results from the tests showed that the scale inhibitor concentration had to be increased considerably when iron ions were present compared to experiments without iron. The scale inhibitors performed poorer at the same inhibitor concentration in tests where iron carbonate particles were present than in tests with iron ions. Scale inhibitor concentrations up to 400ppm were used in the tests without achieving satisfactory scale protection when iron particles were present.
In addition tests with lowering the amount of pH stabiliser have been performed. Tests with combining scale and corrosion inhibitors have also been performed. No scale inhibitors have shown satisfactory performance when iron carbonate particles were present in the tests.
Acoustic Liquid-Level Determination of Liquid Loading in Gas Wells
Authors: Rowlan O. L. , McCoy J. N. , Podio A. L. 
Published: December 2007

Abstract
Acoustic liquid level tests are performed successfully on many different types of wells throughout the world. The most common application of an acoustic liquid level instrument is to measure the distance to the liquid level in the casing annulus of a well. A less common technique is acquiring an acoustic fluid level by "shooting" the well down the tubing. The results from this type of test on a gas well can be used to determine 1) the amount of liquid and backpressure on the formation, 2) the gas rate into tubing, 3) the equivalent fluid gradient below the liquid level, and 4) the flowing bottom hole pressure. In this paper, surface acoustic data (via shooting down the tubing) and bottomhole data were acquired simultaneously to confirm the calculated results from the acoustic data. The benefit of using the portable fluid level instrumentation is such that it permits a simple cost effective test to be conducted quickly to immediately identify underperforming gas wells due to liquid loading problems. The information obtained during this straightforward test provides critical data in determining the well's potential and the ideal artificial lift technique. Fluid level instruments can be used to inexpensively determine liquid loading and its severity for gas wells as opposed to traditional methods, which are more intrusive and costly.
Assessment and comparison of CO2 corrosion predicition models
Authors: Woollam R. C. , Hernandez S. E. 
Published: December 2007

Abstract
A number of different CO2 corrosion rate prediction models have been developed for application in oil and gas production systems and are readily available in the literature or as industry standards. These models vary from the empirical models to the more recently developed mechanistic models.
In this paper a number of CO2 corrosion rate prediction models are compared. In addition to the obvious criteria of comparing the predicted corrosion rates, the models were also compared for other characteristics such as ease of implementation and insight into the main drivers of the predicted corrosion rate.
Using as input the water-chemistry of condensed water, the output from each of the CO2 corrosion prediction models was compared over a range of temperatures and pressures. A common source dataset was used as input for each of the models.
For the range of input values, the suite of selected models generated results which were comparable for lower temperatures and pressures. At higher temperatures and pressures where the effect of the precipitation of iron carbonate would be expected to be influential then the outputs from the models differed. This was in part because in some cases iron carbonate precipitation was not included, but in other cases this difference was due to the alternative implementations of the effect of iron carbonate precipitation.
As would be expected the mechanistic models are the more complex to implement with some being such that specialist computer code is required to numerically solve the systems of equations. However, for all the complexity of implementation, the mechanistic models have the particular strength of providing greater insight into the critical variables driving the overall corrosion mechanism and hence suggest strategies for minimizing the CO2 corrosion risk during design and operation and are therefore to be recommended.