bluuebunny/crossref_metadata_2025 huggingface dataset:
Stand Research and Analysis of Average-Integral Characteristics of Submersible Centrifugal Pumps Operating at Gas-Liquid Mixtures
Authors: Drozdov A. N. , Verbitsky V. S. , Lambin D. N. , Dengaev A. V.
Published: September 2011

One of the major complicating factors in the pumping operation of oil wells is a high free gas content in the pumped fluid at the ESP’s intake.

In the case of compressible media pumping by the blade machinery it is necessary to take into account the change in the density of the pumped medium with increasing pressure for determine the pump’s head.

On this basis, for ESP’s operating at liquid-gas mixture with the compressibility it is required to calculate the values of the pump head on the mixture and the corresponding average-integral value of mixture’s capacity by integration from the intake pressure to the discharge pressure.

The stand investigation was performed and ESP’s average-integral characteristics were obtained on the model gas-liquid mixtures "water – surfactant – gas" at different intake pressures. Consideration of the ESP’s average-integral curves for low-viscosity oil-gas mixtures showed that they are characterized by essentially the same features as on the mixtures "water – surfactant – gas". Average-integral pump performances "head – flow rate" for homogeneous liquids and gas-liquid mixtures are not dependent on the density of the pumped fluid and, consequently, coincide in the case cavitation-free operation, provided that the viscosity is so small that they do not have a noticeable influence on the pump characteristics. If the curves on the gas-liquid mixture are below the pump characteristics on a homogeneous liquid, it is evidence of the development artificial gas cavitation in the pump. The average-integral curves invariance with respect to the mixture density can compare the pump’s characteristics with a different number of stages in mixtures with dissimilar coefficients of solubility of gas and integrate consideration of pump’s performances with different values of the average density of gas-liquid mixture.
The Effect of Chemistry and System Conditions on Hydrate Interparticle Adhesion Forces Toward Aggregation and Hydrate Plug Formation
Authors: Aman Zachary M. , Aspenes Guro , Sloan E. Dendy , Sum Amadeu K. , Koh Carolyn A.
Published: September 2011

The adhesion force between two cyclopentane hydrate particles was directly measured using an improved micromechanical force apparatus. Adhesion forces decreased between 22 and 87% with the addition of approximately 1000 ppm of various carboxylic acid derivatives. The effect of simple, saturated carboxylic acids (such as decanoic acid) may be primarily explained by a decrease in water-oil interfacial tension. More complex carboxylic acids, such as L-lysine and D-tyrosine amino acids, migrate slowly to the water-oil interface and subsequently may be ineffective at weakening the capillary water bridge between hydrate particles in the 30-second formation/destruction timescale. A 4-membered polynuclear aromatic carboxylic acid (1-pyreneacetic acid) exhibited a decreased adhesion force larger than the prediction from decreased interfacial tension, suggesting an alteration in hydrate surface wettability. We present a numerical solution of one hydrate slurry viscosity model for a simple pipeline scenario, where the difference in adhesion force between mineral oil and 1-pyreneacetic acid can shift shear requirements by one order of magnitude.
Modelling the Application of Scale Inhibitor Squeeze Enhancing Retention Additives
Authors: Vazquez O. , Thanasutives P. , Elliasson C. , Fleming N. , Mackay E.
Published: September 2011

The most common method for preventing scale formation is by applying a scale inhibitor (SI) squeeze treatment. In this process, a scale inhibitor solution is injected down a producer well into the near wellbore formation. In the last few years, several publications have presented experimental results, field data and treatment methods showing enhanced squeeze lifetime, due to use of squeeze enhancers.

The main purpose of this paper is to model the effect of SI retention enhancing additives. These additives are normally deployed in reservoirs, where the SI shows poor retention in the formation matrix, in order to reduce the well intervention. In the last few years, a number of techniques to enhance the SI retention have been reported in the literature, such as precipitation squeezes using calcium and/or pH increasing additives, use of additive package that enhances SI adsorption by cross-linking and the injection of non-damaging concentrations of kaolinite, calcium carbonate and organosilane (a solids fixation agent). Specifically the effect of the SI retention enhancer is modelled as a function of the adsorption level of the additive. A sensitivity study is then presented of the effect of deploying the additive in the different stages; normally they are deployed in the preflush stage. However, the aim of this paper is to investigate how the treatment could be optimized to achieve the longest squeeze lifetime with a fixed amount of additive. Example of modelling a specific field treatment injecting organosilane is included. The results are compared with the field return profiles and clearly demonstrate the value such modelling can bring to the interpretation and design of field squeezes.
Novel Polymeric Additives to Improve Oil Sands Tailings Consolidation
Authors: Watson Philip , Farinato Raymond , Fenderson Thomas , Hurd Michael , Macy Pat , Mahmoudkhani Amir
Published: September 2011

It is estimated that the Athabasca Oil Sands in Alberta, Canada, contain 1.7 trillion barrels of oil, but producing one barrel of oil from surface-mined oil sands also produces 1.8 metric tons of solid tailings suspended in 2 m3 of water. Traditionally, tailings slurries were discharged into settling ponds, where solids slowly settled over periods of decades or longer. Since Canadian ERCB Directive 74 went into effect on 1 July 2010, however, regulatory pressure to quickly and efficiently separate tailings from the water has mounted.

Directive 74 mandates that by 1 July 2012, 50% of tailings solids must be removed from waste streams. Furthermore, the captured solids should be trafficable after five years, defined as possessing a shear strength of at least 10 kPa. The flocculation performance of chemical additives ranging from inorganic salts to high molecular weight organic polymers has been previously assessed, but a procedure for meeting Directive 74 is still uncertain because any proposed solution must deal with a wide range of water quality conditions, mineralogical substrates, and particle sizes.

Bench-scale evaluations of novel polymeric additives on Athabasca oil sands were performed in both 1-L graduated cylinders and a thickener. The compactness of captured solids was measured by density and solids content, dewatering was assessed by capillary suction times, and the shear strength of flocculated particles was determined rheologically. The additives were observed to greatly improve flocculation, dewatering, and growth of shear strength relative to conventional polymer treatments.
Improved Microbial Control Programs for Hydraulic Fracturing Fluids Used During Unconventional Shale-Gas Exploration and Production
Authors: Enzien Michael V. , Yin Bei , Love Donald , Harless Michael , Corrin Edward
Published: September 2011

Biocide efficacy studies targeting extended contact times, 7 days, and elevated temperatures, 80° C, led to the discovery of a synergistic combination of Dimethyl Oxazolidine (DMO) and glutaraldehyde. When applied together in specific ratios, most notably a 1:4 ratio of glutaraldehyde to DMO, these two chemistries exhibited superior performance after extended exposure relative to traditional biocide treatments utilizing chemicals such as THPS, glutaraldehyde, and glutaraldehyde/alkyl dimethy benzyl ammonium chloride (ADBAC) blends. The combination of glutaraldehyde and DMO applied in a 1:4 ratio was able to achieve equal performance with lower combined actives. The result of this synergy has a twofold impact on the environmental footprint: it requires less overall biocide for the same level of control, and DMO has a more favorable eco-toxicity profile compared to conventional organic biocides. Field trials on eleven wells and 4 separate well pads in the Marcellus Shale area were treated with the Glutaraldehyde and DMO combination and evaluated using various microbial detection techniques. The benchmark for performance was set by the prior standard chemical treatment in the same shale formation area which utilized the biocide combination, 42.5% active glutaraldehyde and 7.5% active ADBAC blend. Seven wells on three separate well pads treated with Glut/ADBAC were used for comparison to the test wells. The wells treated with the Glut/ADBAC were all dosed at a rate of 300 ppm active ingredient (600ppm product), and the wells used to test the glutaraldehyde/DMO combination treatment were dosed at 200 ppm active (285ppm product). The results of the field trials showed equal or slightly better performance with the combination treatment while utilizing 33% less active chemical, and yielding a reduction of 50% less biocide product applied.
Stabilizing Viscoelastic Surfactants in High Density Brines
Authors: van Zanten Ryan
Published: September 2011

Viscoelastic surfactant (VES) systems are the preferred gelling and viscosity generating agents for fluids used in the production zone due to their non-damaging effects on the reservoir. Polymer gels have relatively higher rock retention values and can often damage the invaded zone, in most cases requiring acid treatment to remove. In contrast, VES systems behave as "equilibrium" or "living" polymers and their viscosity can be reduced by contact with the produced hydrocarbons or with an internal breaker. This can eliminate the need for remedial treatments, greatly reducing operating cost/time and damage to the formation.

Cationic, anionic and catanionic VES systems have historically demonstrated limitations in high density brines. Electrostatic screening generally reduces the viscosity or causes phase separation. Many surfactants generally have low salt tolerance and minimal to zero tolerance of divalent brines. Most surfactants exhibit a drastic decrease in viscosity after a certain concentration of salt is reached and even phase separation in some cases.

A novel method has been found to stabilize different VES packages in high density completion brines. By controlling the curvature of surfactant aggregates using low molecular weight surfactant polymers, nanometer scale manipulation of the phase behavior is achieved. We have viscosified mono- and divalent high density brines using cationic, anionic and catanionic mixtures that were previously considered ineffective. This unlocks a vast range of surfactants for use in high density completion brines, fracturing/stimulation/acidizing fluids and sand control operations.

This paper details the laboratory work performed to develop VES packages for fluids ranging from freshwater to completion brines. Extensive rheology experiments have been run on several fluids showing the viscoelasticity of these systems. The self-breaking nature of VES systems when in contact with hydrocarbons or exposed to a built-in breaker has also been demonstrated by laboratory experiment.
Studies on the Chemical Stability of Glutaraldehyde in Produced Water
Authors: McGinley Heather R. , Enzien Michael V. , Jenneman Gary , Harris Jennifer
Published: September 2011

Description Glutaraldehyde is one of the few biocidal actives approved for use in North Sea operations, and has long been used to protect crude oil pipelines from microbial fouling. However, glutaraldehyde degradation has been observed in produced water (PW). In an effort to understand and control this degradation, stability tests were performed in the laboratory. Specific factors which accelerate degradation were identified. Strategies for dosing glutaraldehyde optimally to maintain microbial control in PW will be discussed.

Application This study is applicable to microbial control and asset integrity in produced water applications. We aim to develop a better understanding of how glutaraldehyde behaves in complex systems so dosing guidelines can be made more robust and customized to specific situations.

Results, Observations, and Conclusions Analysis of glutaraldehyde stability was performed in field and synthetic PW samples. The degradation profile was similar in both water types, indicating a good match between the field and synthetic samples. The most significant factors in glutaraldehyde degradation were temperature and the presence of ammonium chloride. Other factors were also significant, as indicated by the fact that glutaraldehyde in synthetic seawater containing ammonium chloride degrades far slower than in PW at the same temperature and ammonium chloride concentration. Additionally, lower starting concentrations of glutaraldehyde degraded to a greater extent than higher concentrations. This suggests that batch dosing will be more effective than continuous low-concentration doses.

Significance Protection of assets and hydrocarbons from microbial contamination and fouling is a major concern in the oilfield. While effective chemicals for microbial control are readily available, their use is often limited by regulatory, environmental, and compatibility concerns. It is therefore very important to understand the chemistry of the available products in a given system such that the most appropriate treatment can be chosen and applied to maintain adequate microbial control.
Wettability Alteration and Foam Mobility Control in a Layered 2-D Heterogeneous System
Authors: Li Robert F. , Hirasaki George J. , Miller Clarence A. , Masalmeh Shehadeh K.
Published: September 2011

In a layered 2-D heterogeneous sandpack with 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil-in-place (OOIP) due to injected water flowing through high-permeability zone leaving low-permeability zone unswept. In order to enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT) and consequently enabled gravity and capillary pressure driven vertical counter-current flow to occur and exchange fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foamflood was 94.6% OOIP even though foam strength was weak. Recovery with chemical flood (incremental-recovered-oil/waterflood-remaining-oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous force dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental for foam generation. However, the addition of lauryl betaine to NI at a weight ratio of 1:2 (NI: lauryl betaine), made the new NIB blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1-D homogeneous sandpacks, and in an oil-wet, heterogeneous layered system with 34:1 permeability ratio.
Methodology for Dimensioning of the Resources for Construction of the Oil Wells
Authors: Filardo J.. , Morooka C..
Published: September 2011

This paper proposes a new methodology for determining the quantity of physical resources used for the construction of oil wells in relation to the methodology that employs a rough assessment of the curve of resource needs in the time it does not take into account the risks and gains for the business. With emphasis on material resources, and using knowledge of geo-engineering, petroleum engineering, production engineering, economic engineering, project management, artificial intelligence and programming, an equation was established with terms representing the potential revenue from the wells and the costs of excess or the lack of resources in the planning period which enables the knowledge of the optimum quantitative of resources for the company.

The design method has been tested to determine the quantity of pipe casing used in Brazilian exploration wells planned for 2009, based on the configuration of the pre-salt wells.

It is concluded that this methodology has significant gains over the conventional method of analysis by allowing the decision makers to know how much will be your revenue and associated costs, risks and opportunities.
Effect of Water Blocking Damage on Flow Efficiency and Productivity in Tight Gas Reservoirs
Authors: Bahrami Hassan , Rezaee M. Reza , Nazhat Delair , Ostojic Jakov , Clennell Ben , Jamili Ahmad
Published: September 2011

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they might not flow gas at optimum rates without advanced production improvement techniques.

The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include mechanical damage to formation rock, water blocking, relative permeability reduction around wellbore as a result of filtrate invasion and liquid leak-off into the formation during fracturing operations. Drilling and fracturing fluids invasion mostly occurs through permeable zones or natural fractures and might also lead to serious permeability reduction in the rock matrix that surrounds the wellbore, natural fractures, or hydraulic fracture wings.

This study represents evaluation of water blocking damage in tight gas formations, and the influence on core flow efficiency and well productivity. Core scale reservoir simulations were carried out based on a typical Western Australia tight gas reservoir in order to numerically model liquid invasion during overbalanced, balanced and underbalanced drilling, and the effect on gas production in clean-up period. The simulation results describe how water blocking reduces near wellbore permeability and affects well productivity and gas recovery from tight gas reservoirs.
Original-Gas-In-Place Sensitivity Analysis of the Manville Group in the Western Canada Sedimentary Basin
Authors: Contreras Oscar , Aguilera Roberto
Published: September 2011

A sensitivity analysis of the Original-Gas-In-Place (OGIP) in the Manville group of the Western Canada Sedimentary Basin (WCSB) is carried out by using Star Plots in order to determine (1) what parameters have that largest impact on the gas volume estimation, (2) what is the error in the volume estimation, and (3) what is percent error in the choices of effective porosity and Archie’s exponents m and n on water saturation. The Manville group in the WCSB contains a very large resource of natural gas that was quantified to be in the order of 1500 tcf (Masters, 1984).

The gas in place calculations are based on the volumetric equation that takes into account area (A), net pay (h), effective porosity (PHI), true resistivity of the formation (Rt), water resistivity (Rw), porosity exponents "m" and "n," and initial pressure (Pi).

The sensitivity analysis is carried out by choosing possible errors around each input parameter. This permits to concentrate evaluation efforts on the tools and data that have the largest effect on the calculated values of OGIP.

It is concluded that intuition does not necessarily distinguish the data with the largest impact on the calculations. For example, the water resistivity (Rw) is the parameter with the smallest impact on OGIP estimations presented in this study. Based on results, three new polynomial correlations are developed to represent the effect of porosity (PHI) and the m and n exponents on water saturation estimations for the Manville Group. These correlations will improve significantly the way in which uncertainty and risk associated with reserves estimation are quantified.
A Study of Completion Effectiveness in the Williston Basin
Authors: Panjaitan M. L , Cherian B. V , Mata D. , Krishnamurthy J. , Lewis R
Published: September 2011

The evolution in oilfield technology to enable the drilling of longer horizontal wells and increased stimulation effectiveness via isolation has resulted in significant productivity gains. The challenges associated with data gathering, increased well count and understanding connectivity of the recently recognized additional reservoir (Three Forks) has generated concerns regarding the development strategy in the Williston Basin. In order to understand a development strategy it is crucial to characterize fracture properties and reservoir properties. A single well model is developed to capture current well performance to understand the impact of the range of fracture geometries and spacing on production performance. Modeling results and fracture pressure data are also presented to demonstrate the effectiveness of fracture initiation techniques, isolation techniques and number of clusters on fracture geometry generation. The paper presents results utilizing single well modeling techniques (using fracture history matching, production history matching and forecasting) to understand and differentiate reservoir quality, reservoir connectivity and completion effectiveness with the aim of understanding the direction in which completion changes must evolve.
Combining Elastic and Plastic Fatigue Damage in Coiled Tubing
Authors: Bridge C. D
Published: September 2011

Coiled tubing is a continuous pipe that, having been coiled around a reel for storage, can be deployed and used as a pipeline or riser. During deployment as a riser, the coiled tubing is unspooled from the reel, run into the water and connected to the wellhead. This process plastically strains the pipe causing plastic, or low cycle, fatigue damage. When the coiled tubing is connected to the wellhead, the environmental loading causes elastic stress cycles, resulting in elastic, or high cycle, fatigue damage.

There are numerous methods to determine the fatigue life from either plastic or elastic cycling; however, there is little data within the industry on how the fatigue damage from elastic and plastic cycles combine.

This paper presents the experimental work conducted to show the combined fatigue life of coiled tubing that has been plastically and elastically cycled. The data shows that the combined fatigue life can be lower than the summation of the plastic and elastic fatigue damages using Miner's rule. Existing theory suggests that the combined fatigue life could be as low as 10% of the Miner's rule of fatigue damages; however, the experimental data indicates that a more appropriate value is closer to 75% of the Miner's rule fatigue damage.
Operational Benefits of Coiled Tubing Enabled with New Real-Time Data Communication System
Authors: Taggart Michael , Murray Niall , Sturgeon Trevor
Published: September 2011

A recently developed system enabling real-time data to be transmitted from intelligent downhole tools to surface recording and display equipment has been in use for over 12 months. This system is engineered so that there is negligible impact on conventional Coiled Tubing operations. Coiled Tubing weights and surface pump pressures are almost unaffected by the presence of this system and ball operated tools can be operated with confidence.

The primary purpose of the system is to allow accurate control of the position of the BHA, previously not achievable with conventional coiled tubing. Trials using this new system have been completed. In addition to confirming the operational ability of the system, the data-stream revealed previously unrecognised information. The benefit of this additional information will enhance the operational success of many coiled tubing operations.

Field operations completed with the system to date, have demonstrated the benefits of a system transmitting downhole information while completing a wellbore intervention. The operations discussed show the advantages of a system that allows accurate depth control while maintaining the functionality of coiled tubing, such as ability to circulate fluids through the coiled tubing and function ball operated tools.

This paper describes the system components, injection equipment and discusses the findings revealed during system trials. Many operations with the system have been completed since introduction and operational and benefits confirmed during these operations are outlined. Operations involving the use of logging tools have been completed and have proven the advantages of the system, with combining the abilities of conventional coiled tubing with real-time coiled tubing logging operations.
Best Practices for Multizone Stimulation Using Composite Plugs
Authors: Lehr D. J. , Cramer D. D.
Published: September 2011

Treatment isolation using composite bridge plugs (CP) has been practiced for about 18 years in North America and continues to be among the most economical ways to stimulate horizontal and multi-layer vertical wells. Despite this long experience, many end users still experience problems in these applications because of sub-optimal choices regarding product selection, run-in and removal options, and unrealistic expectations regarding plug life in downhole environments.

This paper will identify best practices for using CPs, based on prior technical papers, field experience, and manufacturers' published data. These practices maximize the chances of successfully installing and removing CPs in multi-zone treatment applications, improving the economics of oil and gas plays requiring multiple stimulation treatments per well.

As multi-zone completion activity increases in regions outside of North America, treatment applications using CPs will also increase in those regions. Realizing the benefits of using CPs in emerging regions will be achieved by learning about best practices from regions with extensive experience in their use.
New Hybrid System Brings the Flexibility of Coiled Tubing to Long, Extended-Reach Wells
Authors: McNeil F. , Lindsay S. D. , Lyons R. , Gracey R. P.
Published: September 2011

The number of long, extended-reach wells being drilled in the oil and gas industry continues to increase. These wells present complex challenges in completion and intervention procedures because operators demand the same level of performance achieved on shallower wells while providing a cost-effective and safe solution.

To reach deep target depths with coiled tubing (CT), smaller coil must be used because of reel capacity, which limits pumping rates because of pressure and velocity limitations. Many areas have road weight restrictions that will also dictate the size and length of CT that can be used. As an alternative, jointed pipe can be used; however, using jointed pipe reduces the overall efficiency of the process, as continuous pumping cannot be achieved.

The new hybrid system uses both CT and jointed pipe in a single workstring. The system incorporates a unique flapper safety valve that enables seamless functioning of the string in a live well. The hybrid system enables larger CT and jointed pipe to be deployed, which results in higher pumping rates and depths. This reduces the overall job time, while improving safety and efficiency for deeper well applications, including multizone stimulation, cleanouts, drilling, and mill-outs.

This paper presents the hybrid system design and benefits in multizone stimulation, drillouts, cleanouts, and other well-intervention applications. Also included is a case history to demonstrate the success of the system when applied in a multizone fracture-stimulation treatment.
Accurate Downhole-Temperature Estimates are Critical to Proper Slurry Design-Improved Data-Collection Method Field Tested Successfully
Authors: Velazquez F. Santillan , Arias R. Aguilar , Castro J.. , Cerón F. Evar , Rogers H..
Published: September 2011

Temperature is a parameter of great importance when simulating and modeling cementing or temperature-activated fluids (McSpadden and Glover 2008) because it affects the amount of retarders or accelerators needed to avoid undesired phenomena, such as premature cement setting or incomplete consolidation of the treatments. In 1964, API introduced the first set of tables (API 2005) that listed the circulating temperatures and hydrostatic pressures for certain wellbore circumstances and bottomhole conditions and the fluids that could be used in different well treatments, such as cementing, lost-circulation control, and water or gas control, etc. The API procedures have been widely adopted and recognized in the oil industry, and most operating companies feel comfortable using them. However, increased demand for oil and gas has forced operators to perform drilling, completion, and maintenance operations in deeper and more complicated zones. These zones are often classified as high-pressure/high-temperature (HPHT) fields.

Currently, combining computational tools, such as computer simulation software and measurement sensors, allows operators to accurately measure temperature and pressure values and adjust them with well-known heat-transfer models; as a result, possible temperature changes during complex operations can be more accurately modeled. This paper presents multiple case histories showing the significance of using bottomhole pressure/temperature (P/T) measurement tools and the modified modeling of the heat-transfer effects as a function of operational parameters (flow rate, density, wellbore geometry). With more accurate temperature data, laboratory testing can be performed to better predict the behavior of the treatments mentioned when exposed to the more complex bottomhole conditions encountered.
Assessing Well Integrity Risk: A Qualitative Model
Authors: Dethlefs J. C. , Chastain B.
Published: September 2011

For successful delivery of Well Integrity, there needs to be an understanding of the risks that can cause undesirable events such as safety hazards or loss of containment. Performing a risk assessment on a well, or type of well, will help determine and rank the potential risks and provide information that allows limited resources to be applied in the most effective manner. The main objectives of performing a risk assessment include: Follow a formal process to assess risk consistently and to enable comparison between well barrier failure mode scenarios;Qualitatively assess well barrier failure risk for every segment of a well;Document suggestions that are offered by the risk assessment team for mitigating well barrier failure risk; andProvide a report of the methodology, failure mode scenarios, risk ranking, and potential mitigation actions for use as a reference tool for managing well integrity on a routine basis.

The Well Integrity Risk Assessment Model follows a common qualitative risk assessment process; a team-based, structured brainstorming format, utilizing the What-If Methodology, to identify potential hazards associated with well barrier failure modes. In addition, the model has the following attributes: Incorporates a unique method to segment well barriers into discrete sections, successively "failing" each section for evaluation. The list of analyzed well barrier failure modes, along with their risk ranking, becomes the risk register for the well or type of well.Is adaptable for assessing well barrier failure modes on a single well, or a group of wells, having the same general design parameters. An entire well portfolio can be assessed quickly by analyzing types of wells rather than individual wells.Can be used to assess well barrier failure risk for any type of well.The model can easily be modified to conform to any company's risk model.

The Well Integrity Risk Assessment Model has been proven to: Successfully assess well barrier failure risk for thousands of wells;Focus specifically on well barrier failure modes, and as a result is an effective tool that should be incorporated into a "Best in Class" Well Integrity Program;Be utilized as a management tool to provide guidance for how limited resources can be used effectively to continuously deliver well integrity.
Unified Reservoir / Well / Network Model for Advanced Processes
Authors: Moncorgé Arthur
Published: September 2011

A formulation for the fully coupled simulation of reservoir, well and network for advanced processes is described in this paper. The governing equations for the reservoir, well and network are generalized into the same finite volume framework. The approach is close to Shiralkar and Watts (SPE 93073) but it uses natural variables and is generalized to: (1) energy and aqueous components (polymers, surfactants, salts, …) conservation equations, (2) mass and energy accumulation terms in the wells and the network to simulate transient effects, (3) acceleration terms in the wellbore. The motivation of this work is to have a consistent formulation for the reservoir, the well and the network, allowing (1) no limitation in the well/network architecture, (2) ease of implementation and maintenance, (3) use of advanced linear solvers.
Negative Saturation Approach for Compositional Flow Simulations of Mixed CO2-Water Injection into Geothermal Reservoirs, Including Phase Transition and Disappearance
Authors: Salimi Hamidreza , Wolf Karl-Heinz , Bruining Johannes
Published: September 2011

Cold mixed CO2-water injection into hot-water reservoirs can be used for simultaneous geothermal-energy (heat) production and subsurface CO2 storage. This paper studies this process in a 2D geothermal reservoir for a homogeneous reservoir, a layered reservoir, and a heterogeneous reservoir represented by a stochastic-random field. We give a set of simulations for a variety of CO2-injection concentrations. In this process, often regions of two-phase flow are connected to regions of single- phase flow. Different systems of equations apply for single-phase and for two-phase regions. We develop a solution approach, called the non-isothermal negative saturation (NegSat) solution approach, to solve efficiently non-isothermal compositional flow problems (e.g., CO2-water injection into geothermal reservoirs) that involve phase disappearance, phase appearance, and phase transition. The advantage of the solution approach is that it circumvents using different equations for single-phase and two-phase regions and the ensuing unstable switching procedure. In the NegSat approach, a single-phase multi-component fluid is replaced by an equivalent fictitious two-phase fluid with specific properties. The equivalent properties are such that in the single-phase aqueous region, the extended saturation of a fictitious gas is negative.

We discuss the salient features of the simulations in detail. When two phases are present at the injection side, heterogeneity and layering lead to more CO2 storage compared to the homogeneous case because of trapping. In addition, layering avoids movement of the CO2 to the upper part of the reservoir and hence reduces the risk of leakage. Our results also show that heterogeneity and layering change the character of the solution in terms of useful-energy production and CO2 storage. The simulations can be used to construct a plot of the recuperated useful energy versus maximally stored CO2. Increasing the amount of CO2 in the injection mixture leads to bifurcation points at which the character of the solution in terms of energy production and CO2 storage changes. For overall injected CO2 mole fractions less than 0.04, the result with gravity is the same as the result without gravity. For larger overall injected CO2 mole fractions, however, the plot without gravity differs from the plot with gravity due to early breakthrough of a supercritical-CO2 tongue near the cap rock. Including gravity, we have a choice of optimal energy recovery 1273 TJ with a limited CO2 storage of maximal 2449 kton or minimal energy recovery of 437 TJ with maximal CO2 storage of 9388 kton.
Downhole Chemical Injection Through Gas Lift: Options and Consequences
Authors: Daas M. A. , Golczynski T. S. , Magalhães A. A. , Bastos E. C. , Ferreira P. A.
Published: September 2011

Gas lift is being utilized to enhance production of heavy crude from the Campos field offshore Brazil. Downhole chemical injection is implemented to treat the crude and assist with chemical inhibitor delivery to protect the reservoir fluids in the well tubing from corrosion due to elevated concentrations of hydrogen sulfide (H2S). Due to the absence of dedicated chemical injection lines in the field, H2S scavenger is diluted in ethanol and transported with the gas lift, through the gas lift line (GLL), to the well casing. The gas lift and aqueous chemical phase flow together in the inner annulus between the casing and tubing as a multiphase mixture. The mixture is then injected into the well tubing through a gas lift valve (GLV). Field measurements have shown the crude is not always uniformly treated with the chemicals due to unsteady discharge of the chemicals from the casing into the production tubing through the GLV.

Advanced steady state and transient simulations were carried out to analyze the supercritical / multiphase flow in the gas lift system. Moreover, the complex phenomena associated with the hydraulic instability upstream of the GLV, and subsequent irregular injection of the multiphase mixture into the tubing, were well-characterized.

Simulation results are qualitatively accurate and descriptive as they duplicate the phenomena observed in the field. It was found that the dynamic stability of the wellbore was disturbed by either insufficient pressure gradients at the GLV or by localized slugging initiated in the casing. As such, chemical accumulation in the casing and intermittent pressure build-up upstream of the GLV were responsible for the non-uniform injection into the well tubing. The system’s dynamic stability can be restored by either increasing the casing pressure to a level high enough so the GLV tolerates normal variations in the casing pressure or by manipulating the flow pattern in the casing to avoid slug flow. Simulation results proved both techniques to be effective.

Field data and simulation results show that GLL may be substituted for chemical injection lines provided the GLV is designed based on a sound understanding of the system’s hydraulics and a reasonable prediction of the operating pressures on its sides throughout the well life.

Findings from this study provide guidelines for proper flow assurance practice and safe design and operation in artificial gas lift and chemical injection applications
Inversion of Time-Lapse InSAR Data for Reservoir Pressure Monitoring: Example of the Krechba Field, Algeria
Authors: Lecampion B. , Cooksley G. , Loizzo M. , Arnaud A. , Robles J. Garcia , Zhang Z. , Sheng X.
Published: September 2011

Time-lapse lapse interferometric synthetic aperture radar (InSAR) images provide accurate surface deformation over a large area and are sensitive to fluid injection/production at industrial scale. The quality and quantities of surface deformation time series open new opportunities for reservoir management. In this paper, we investigate the resolution of pore pressure change from InSAR highlighting some intrinsic features of such type of measurements (i.e. loss of resolution with distance to source). Depending on the relative ratio of the reservoir depth over the source lenghtscales (e.g. reservoir extent), we propose two new robust inversion schemes consistently tackling the issue of loss of resolution without additional information: i) multipole moment decomposition for far-field case and ii) decomposition of the pore-pressure field change via Chebyshev series truncated at the order governed by the expected resolution.

The example of the Krechba field illustrates our discussion. In particular, we show, using a far-field decomposition that the center of the pressure source remains in the reservoir layer around the KB501 injector and we recover quantitatively the direction of the flow anisotropy. We also discuss the direct inversion of the pore-pressure changes via Chebyshev decomposition. The requirement of a fast but accurate enough geomechanical model is emphasized in order to integrate time-lapse InSAR images with other conventional measurements for history matching purposes.
Innovative Pattern Balancing and Waterflood Optimization of a Super Giant Carbonate Mauddud Reservoir, Raudhatain Field, North Kuwait
Authors: Al-Ajmi Moudi , El-Daoushy Ahmed , Ashkanani Fatma , Saleh Iskandar , Pathak Ashok , Hamadi Hajer
Published: September 2011

Raudhatain-Mauddud, a super-giant depletion-drive oil reservoir in North-Kuwait, is undergoing massive development efforts, with a planned enhancement in oil production through phased pattern-waterflood. The Phase1-development covers the crestal-area of the structure, which is the focus for current development efforts through 8 inverted 9-spot patterns. This poster outlines the successful integration of a lot of team's collaboration to significantly improve the operating procedure for water flooding. This effort required a new way of managing this reservoir: a comprehensive approach of balancing voidage with injection, conducting extensive surveillance/analysis to assess the efficacy of various courses of action and, most significantly, adjusting various teams' "key performance indicators" to align injection and production allowable with sound reservoir management principles.

An innovative unified information management system was used to monitor voidage replacement ratio (VRR) to provide a basis for pattern balancing. A very extensive surveillance operation provides the data necessary to monitor individual pattern balance and water cut performance, optimizes areal sweep efficiency by adjusting injection and production allowable, assist in planning water-shutoff operations, and design new completions.

Time lapsed monitoring and the surveillance data indicates the reservoir is relatively well connected. However, after applying the new management approach, individual waterflood pattern balance is significantly improved and the field-wide VRR is around 1.2.

All of these activities have led to the enhanced understanding of the waterflood behavior and the model updates. Sound reservoir surveillance and waterflood management procedures implemented within a diverse group of teams that have performance goals aligned with "best practice" has resulted in effectively re-balancing this major waterflood.
A Novel Approach for Breakout Zone Identification in Tight Gas Shale
Authors: Soroush Hamed , Qutob Hani , Rasouli Vamegh , Tokhmechi Behzad
Published: September 2011

The decline of production of conventional reservoirs and increase in demand of hydrocarbon fuels bring the tight gas into the forefront of the energy future. This unconventional energy source is a fast-growing market and is recognised as having huge future potential for production worldwide. Low permeability of tight gas shale requires conducting effective hydraulic fracturing and applying horizontal drilling technologies to produce at commercial level. Therefore, successful production from such complex reservoirs is heavily dependent on the selection of an appropriate completion technology requiring sufficient knowledge of borehole shape. Therefore, understanding the rock properties and the earth’s stresses (Geomechanical Model) is the first critical step in reservoir evaluation and ultimately development of these resources. In order to determine in-situ stress condition and calibrate geomechanical models, having information of borehole breakouts existence plays a key role.

Caliper and image logs, the regularly used methods to identify breakout zones, have several limitations such as not having a full coverage of the borehole wall, being affected by different parameters, pad width limitation, low resolution, and complicated processing procedure. In addition, good quality image logs are not usually available for shaly formations because of the requirement of using oil-based mud.

This paper presents a new multi-variant approach to identify borehole breakouts in tight gas shale using some petrophysical logs. This approach employs number of data processing techniques, including Bayesian classification, wavelet decomposition and data fusion, to determine borehole intervals with maximum likelihood of enlargement. The results approved the applicability and the generalization capability of the approach with a significant accuracy. Case study on Burnett shale is presented in this paper.
New Higher-Strength Coiled Tubing Developed to Extend Coiled Tubing Operating Envelopes
Authors: VanArnam W. D. , Hargis C
Published: September 2011

A new high strength coiled tubing grade has been developed to address the demands for improved axial strength, better fatigue performance and the ability to function at higher operating pressures. Coiled tubing service companies and operators defined several areas where existing coiled tubing grades are not considered capable of performing, including carrying heavier payloads to the well perforation zone and working in today's increasingly longer horizontal sections. Designing a coiled tubing product that meets these requirements presented unique challenges. The project goal was to develop reliable high strength coiled tubing that provides 130,000 psi minimum yield strength and predictable fatigue life. Coiled tubing strength comes from a balance of strength from the initial hot rolled strip and modifications while forming into tubing. However, some coiled tubing manufacturing operations, including welding, can influence those strength characteristics. The process controls during manufacturing, including bias welds and any tube to tube welds needed to assemble long strings; all determine the final properties of the tubing. The high strength tubing has been successfully made using existing manufacturing methods. The initial testing indicates the tubing has high strength with good ductility. Fatigue testing shows superior fatigue performance to existing grades of tubing in both cycles to failure and diametrical growth. This paper will cover the development program inclusive of strip manufacturing, tube forming, welding and other processes including the quality control necessary for assuring consistent properties. Initial application trails to verify operating characteristics will also be reviewed in the paper.