bluuebunny/crossref_metadata_2025_split huggingface dataset:
Foam Cement Engineering and Implementation for Cement Sheath Integrity at High Temperature and High Pressure
Authors: Griffith James E. , Lende Gunnar , Ravi Kris , Saasen Arild , Nødland Nils Egil , Jordal Ole Henrik 
Published: December 2007

Abstract
Cementing high-pressure, high-temperature (HPHT) wells poses various challenges not seen at normal well conditions. For instance, the following objectives are critical for HPHT wells:
Prevent losses during drilling fluid circulation and cement slurry placement. Displace the drilling fluid and place the cement slurry effectively. Prevent free-water or gas-channel development. Reduce slurry fluid loss. Provide support for the production packers. Decrease compression loads on casing connectors. Prevent damage to cement sheath. Prevent annular gas pressure over the life of the well.
The industry is recognizing the interaction between these factors to determine the optimal cement job design for accomplishing these objectives. This paper presents and discusses the engineering analysis to determine the optimum foamed cement sheath properties for integrity during the life of the well at HPHT conditions. Also, this paper compares foamed cement to nonfoamed slurries in achieving these objectives. Other important issues discussed are the performance of nitrogen at HPHT conditions and the rheological properties of the foams. Key issues addressed are the state and solubility of nitrogen under downhole conditions and the integrity of the cement sheath during the life of the well. Thermodynamic solution theory and experimental studies are applied to the former, and finite element analysis is applied to the later.
Case examples are presented discussing foamed and conventional operations at near HPHT conditions for some Norwegian, North Sea wells. Cement properties are contrasted for the different foamed and conventional cement slurry properties with respect to:
Achieving the HPHT objectives, such as placement efficiency and sheath properties Prejob design to obtain the objectives Job planning and procedures Job execution Logging of foamed cement Post-job evaluation of the cement systems
New Expandable Cladding Technique Enables Extended Length Casing Repair
Authors: Jabs Matthew , Harmon Charles E. , Harmon Steve C. , Harmon Robert E. 
Published: December 2007

Abstract
In June 2003 a project in south central Oklahoma incorporated the first use of an expandable metal casing patch technology to repair a damaged well bore casing section. The cladding was deployed to correct a casing collapse problem that occurred when an offset injector well went online and caused the existing casing to fail. The well has been an oil producer and was originally drilled in the early 1950s. This technology provides the operator with the ability to create a definitive casing repair with pressure integrity and minimal well restriction.
Drilling Salt Formations Offshore With Sea Water Can Significantly Reduce Well Costs
Authors: Willson Stephen M. , Driscoll Pete , Judzis Arnis , Black Alan , Martin Wes , Ehgartner Brian , Hinkebein Tom 
Published: December 2007

Abstract
Rate of penetration (ROP) increases significantly if salt formations are drilled using undersaturated fluids. This is especially true when drilling riserless. Of primary concern is the amount of hole enlargement that will occur. However, if managed, then a step-change in drilling performance and costs can be achieved.
This paper presents, in detail, the results of a comprehensive and large-scale laboratory testing program performed on outcrop salt samples that replicate drilling salt formations with undersaturated drilling fluids with flow rates of up to 1000 gpm. The laboratory-testing program includes tests performed in a CT-scanner to map hole enlargement in real-time, as well as variously sized borehole leaching tests with borehole diameters of up to 6". Flow rates are scaled to produce comparable levels of turbulence occurring in the field.
An analytical hole enlargement prediction model is presented that incorporates the effects of ROP, pump rate, drill-fluid saturation, dissolving salt drill-cuttings and salt leaching from the borehole wall. This model accurately predicts, to within 10%, the measured hole enlargements produced in the scaled laboratory tests, for a wide range of flow rates and fluid saturations.
Predictions of field performance are made, and the implications of the predicted hole geometry discussed. Provided high rates of penetration are realized, acceptable hole geometries will result, even when pumping seawater at flow rates of up to 1600 gpm. A field application is described, whereby the historical practice of drilling the last 200 ft of the 20" hole into salt using a saturated brine drilling fluid was discontinued in preference to continued use of seawater. The competing influences of increasing rate of penetration and avoiding the cost of a sacrificial mud system, offset by the increased cost of cement, resulted in cost savings of $250,000 per well. Implemented in a multi-well sub-salt development, cost savings of over $1.5 million will be realized in the drilling program. Further applications of this technology are now being sought.
Bounds on In-Situ Stress Magnitudes Improve Wellbore Stability Analyses
Authors: Aadnoy Bernt S. , Hansen Ann K. 
Published: December 2007

Abstract
Wellbore stability analysis is becoming a necessary tool to improve operational economy and to avoid wellbore problems. Essential elements here are estimation of critical fracturing and collapse pressures to obtain an optimal mud weight window.
The input data for this analysis is mainly pore pressure predictions from many sources like logs and drilling exponents, overburden stresses from logs or drilled cuttings, leak-off tests at casing shoes and breakout analysis from caliper logs. From these and other data, estimates for in-situ stresses and directions are obtained, which again serves as input for wellbore stability modeling. It is evident that the input data comes from many different sources and can therefore not be considered consistent.
During wellbore stability modeling it has often been observed that unrealistic results appear. Sometimes one observes a critical collapse pressure that exceeds the fracturing pressure, clearly a faulty result. These results are often ignored. However, there must be an inherent error in some of the input data. This paper addresses this problem and concludes that the relative magnitudes of the in-situ stresses are the main cause of this. Equations are given that defines the bounds on the in-situ stresses for different stress regimes.
Using the bounds on the horizontal in-situ stresses on field cases, realistic fracturing and collapse prognosis are always obtained. Since the models also define the minimum permissible anisotropic stress state, these can be used as default parameters when field data are missing.
A field case from the North Sea demonstrates the application of the stress bounds, and shows that prognosis are obtained that better corresponds to observed behavior of the wells.
Improved Bottomhole Pressure Control for Underbalanced Drilling Operations
Authors: Pérez-Téllez C. , Smith J. R. , Edwards J. K. 
Published: December 2007

Abstract
Maintaining underbalanced conditions from the beginning to the end of the drilling process is necessary to guarantee that underbalanced drilling (UBD) operations successfully avoid formation damage and potential hazardous drilling problems such as lost circulation and differential sticking. However, maintaining these conditions during operations with jointed-pipe is an unmet challenge that continues motivating not only research but also technological developments.
This paper proposes an improved UBD flow control procedure as an economical method for maintaining continuous underbalanced conditions in jointed-pipe UBD operations by maximizing the use of natural energy available from the reservoir through the proper manipulation of nitrogen and drilling fluid injection flow rates and choke pressure. It is applicable to wells that can flow without artificial lift and within appropriate safety limits.
The flow control procedure is based on the results of a new comprehensive, mechanistic steady-state model, validated with both field data and full-scale experimental data, and on the results of a simplified, time dependent, mechanistic model, which numerically combines the accurate mechanistic, steady-state model, the conservation equations approximated by finite difference, and a well deliverability model.
Thermal Modeling of Shut-In Well After Multiphase Hydrocarbon Production
Authors: Shah P. C. 
Published: December 2007

Abstract
When a well that has been producing a mixture of oil, water and gas is shut-in for an extended period of time, the fluid columns expand or contract in response to the temperature changes in the well. These changes in fluid levels in turn, affect the heat transfer in and around the wellbore. This coupled problem of determining the fluid levels as well as the wellbore temperature distribution is addressed. An algorithm is proposed, implemented and discussed for a hydrocarbon that can be modeled as a black-oil. Special cases of the algorithm when one of the phases is absent are also included.
This model helps accurate and rigorous prediction of the wellbore temperature distribution and the wellhead pressure during a shut-in. Accurate temperature and pressure estimates in turn lead to better stress calculations to ensure the design of the wellbore with improved integrity of the tubulars.
Field Experiences Using ‘Oil Soluble’ Non-Aqueous Scale Inhibitor Delivery Systems
Authors: Miles A. F. , Vikane O. , Healey D. S. , Collins I. R. , Saeten J. , Bourne H. M. , Smith R. G. 
Published: December 2007

Abstract‘Oil Soluble’ scale inhibitor delivery systems are believed to have been first applied to an onshore well in Colombia in 1997. Products of a similar type have since been used in a number of applications including wells in the UK and Norwegian Sectors of the North Sea and in North America.In addition to oil soluble products, other technologies designed to avoid the problems sometimes observed with aqueous treatments have also been developed and deployed in similar, challenging, environments. The different technologies are now commonly referred to as non-aqueous systems to distinguish them from more traditional, aqueous methods.This paper will review each of the non-aqueous technologies currently available followed by a detailed description of field experiences, both good and bad, found by BP, ChevronTexaco, Statoil and other operators using oil soluble systems. Where problems were encountered, the laboratory work to investigate these difficulties will be described and the main findings presented. Recent advances using the knowledge gained from the investigation of earlier challenges will also be presented.
An Unconventional Scale from an Unconventional Reservoir
Authors: Sitz Curtis , Shumway Jacob , Miller Cindy 
Published: December 2007

Abstract
As gas fields are developed around the world, new and interesting scale challenges are presented. In the United States, gas reserves are found in fields near Green River, Wyoming. This gas is produced from shale layers interbedded with the carbonate mineral trona, or, sodium sesquicarbonate, Na3H(CO3)2*2H2O. Well known carbonate minerals, such as calcite, siderite, and dolomite are relatively insoluble in water, and are often found in the rock matrix of hydrocarbon reservoirs. Unlike these conventional minerals, trona is extremely water soluble at reservoir conditions. Under normal circumstances, if left untreated, the production of the mineral saturated brine leads to significant deposition of scale in the production tubing and surface facilities.
Two major challenges are presented with trona scale deposition.
The first challenge is in the prevention of the mineral deposits. Like conventional carbonate scales, inhibition is possible with chemical inhibitor treatment. There are also non-typical treatment options, both chemical and thermodynamic, that were investigated and evaluated for effectiveness.
The second challenge is in the removal of deposited scale. It is common to remove carbonate scales by the application of an acid, but the trona scale is an unusual exception. The addition of an acid actually encourages deposition since the composition and solubility of this mineral scale are very sensitive to changes in pH.
This paper discusses the laboratory work performed that led to an understanding of the problem and to the proposal of rather unconventional procedures necessary to prevent the scale and to eliminate the existing deposits.
The Challenge of Squeezing a Water Sensitive HP/HT Reservoir - Lab and Field Experiences with a Novel Non Aqueous Inhibitor/Squeeze Enhancer Package
Authors: Chen Ping , Hagen Thomas , Bourne Hugh , Turner Katherine , Nielsen Frank Møller , Rian Mette , Haldoupis Andreas 
Published: December 2007

Abstract
Down-hole scale control in Statoil's Åsgard field presents a particularly severe challenge. The field is producing from low permeability formations with a high draw down, through subsea templates. System pressure and temperature changes experienced during production promote the formation of carbonate scales, which have been identified in the near well bore area and perforated intervals. The high formation temperature and pressure, 165°C and 500 bars respectively, high chlorite content coupled to the water sensitive nature of some of the formations creates a challenging environment for downhole scale treatments.
This paper will describe possible formation damage mechanisms that were identified for this water sensitive formation and the treatment strategy adopted to minimize them. It also presents the extensive laboratory studies that were undertaken to develop a non-damaging, non-aqueous inhibitor/squeeze enhancer formulation suitable for deployment under these harsh conditions. An understanding of the mechanisms by which the squeeze treatment package prevented water block formation and clay mobilization under such severe temperature and reservoir constraints, coupled to the mechanisms of squeeze life extension are discussed. The paper will also highlight the manufacturing challenges that were overcome to improve the environmental profiles of the products.
The paper will finally discuss the two treatments, which have been performed to date with the non-aqueous products. Initial field data demonstrates that the application of this nonaqueous product package significantly reduced the potential for formation damage and allowed the successful treatment of these wells. Residual inhibitor returns remain significantly above MIC and a long squeeze life is expected for both wells.
Development of an Enzyme Activated, Low Temperature, Scale Inhibitor Precipitation Squeeze System
Authors: McRae J. A. , Heath S. M. , Strachan C. , Matthews L. , Harris R. 
Published: December 2007

Abstract
Since the early 1990’s scale inhibitor precipitation technology has been routinely used throughout the North Sea to provide improved placement and extended treatment lifetimes when compared to conventional aqueous-based scale inhibitor squeeze treatments. Controlled precipitation technology is based upon the deployment of a specially formulated scale inhibitor package containing an organic additive that breaks down thermally and acts as a pH modifier resulting in in-situ scale inhibitor precipitation. However, the reliance on thermal degradation of the organic additive to cause precipitation means that this technology is limited to use in wells at temperatures &gt; 85°C.
This paper describes the development of a low temperature, scale inhibitor precipitation delivery system. The new system is based upon the use of novel enzyme technology to break down the pH modifier using a non-thermal mechanism, thus allowing product deployment at low temperatures previously unavailable to the thermal degradation systems. Laboratory studies have so far indicated that the enzyme is effective at inducing scale inhibitor precipitation at both 40°C and 80°C.
A description of the laboratory development and evaluation of the new enzyme precipitation technology including enzyme assay, full analysis of the precipitation mechanism and core flood studies to evaluate formation damage potential and retention and release characteristics will be presented.
This paper will also highlight how the use of the enzyme precipitation process can increase squeeze lifetimes when compared to traditional adsorption squeeze treatments at low temperatures.
Scale Management of Production Wells via Inhibitor Application in Supporting Injection Wells
Authors: Ragulin V. , Mikhailov A. , Latipov O. , Voloshin A. , Tyabayeva N. , Mackay E. 
Published: December 2007

Abstract
At the present time, the YUKOS Oil Company is applying various techniques to maximize oil recovery. Some of these techniques, such as waterflooding, are leading to an increase in the number of wells that face scaling problems. Various technologies are being used for scale management in these wells, including, for example, continuous inhibitor dosing utilising surface dosing systems. This method has some disadvantages, including the high cost of the service. In addition, this technology only protects downhole equipment from damage by scale deposits, but the bottomhole formation zone remains unprotected. Some years ago we recommended that production wells be protected via scale inhibitor application in the injection waters used for reservoir pressure control and sweep. Experiments conducted have shown that this technique may be used for certain production well types with scaling problems when these are located in relatively close proximity to their supporting injection wells.
This paper presents the experimental and field results when this technique was tested in the South-Surgut oilfield. Before testing, a preliminary investigation of the formation geology and hydrodynamic connectivity between injection and production wells was carried out. Next, a large number of experiments were carried out to select an efficient inhibitor chemistry, to test for inhibitor adsorption on the reservoir rock, to evaluate an initial MIC for the solution, and to determine the inhibitor dosing periodicity.
During testing of this technique, the inhibitor concentration in the produced water was regularly measured, and the impact on protection against scale was continuously evaluated. It was demonstrated that the inhibitor concentration in the produced water did not decrease below 5- 10 ppm on average during 150-200 days for all wells. As a result, the interval between workovers for pump equipment increased by approximately 2.5 times. Furthermore, oil production was increased relative to the period before introduction of this technology. An economic evaluation was carried out that showed the viability of using this technology for the protection of wells in a compact injector-producer pattern.
Sulphate Removal for Barium Sulphate Scale Mitigation a Deepwater Subsea Production System
Authors: Collins I. R. , Stalker R. , Graham G. M. 
Published: December 2007

Abstract
Scale control is conventionally achieved by use of chemical inhibitors, introduced to the production system either by squeeze treatment into the reservoir or continual injection into the well. However, as new field developments encounter more challenging production environments or when the associated economic impact of chemical intervention is large (e.g. subsea completed wells with poor chemical placement by bullhead treatments, or limited access to wet subsea wellheads), other methods of scale control such as sulphate removal must be considered during the front end engineering design (FEED) stage.
The Greater Plutonio development, lying in deep water (500 – 1600 metres) off the coast of Angola, will be produced via multi-well subsea facilities tied back to a floating production vessel, with reservoir pressure support being provided by seawater injection. Owing to the complex and inaccessible nature of the subsea production system, chemical control of sulphate scale was considered economically unfeasible. Scale control will therefore be achieved by means of sulphate removal prior to seawater injection. However, following conventional sulphate reduction towards 40 ppm there remains a residual scale potential, the impact of which on production is difficult to assess using thermodynamic scale prediction packages or normal laboratory conditions. Periodic squeeze treatments were however still anticipated. A detailed laboratory testing programme of dynamic and static scale formation tests coupled with dynamic core-blocking tests was undertaken to determine the effect of varying production conditions, organic acid content, flow regime and the nature of the underlying substrate on scale formation under field specific conditions for this mildly oversaturated system. The ultimate goal of the laboratory test programme was to define an optimal sulphate level in the injected seawater to prevent scale formation throughout the production lifetime of the field. By comparison of laboratory test results with predicted scale formation tendencies, an acceptable level of sulphate in the injected seawater was determined which would allow pressure support without causing scale formation. This allowed further detailed analysis of the costs associated with a residual scale risk at 40 ppm sulphate (or above) with the costs associated with upgrading the SRP facility to achieve lower levels of sulphate in the injection water. The laboratory work allowed an optimal sulphate concentration to be determined which was achievable through modification of the current design facilities and resulted in a significant cost saving in the development phase.
Groet 1 Scale Study: Analysis, Diagnosis & Solution Implementation
Authors: Nieuwland H. F. , Collins I. R. 
Published: December 2007

Abstract
Gas well Groet 1 (GRT1), located onshore in the Netherlands, has been experiencing unstable production for six months since Q1 2002. A down hole video survey identified salt (halite) deposition in the tubing which was subsequently removed by a gauge cutter. The problem reoccurred in Q4 2002 leading to an 8.3 MBOE loss in the quarter. A scale prediction study was conducted to analyse the problem arising with well GRT1 and to diagnose whether the scaling problem is transient or persistent. This study indicated that the scaling behaviour is persistent. Several remedial actions and control options were considered, based upon the diagnosis. All of the remedial actions and control options were compared on a risk / cost / benefit basis. The outcome of this study was that the most economical and lowest risk halite control option was bi-weekly fresh water soaks.
pH-Stabilisation, a Reliable Method for Corrosion Control of Wet Gas Pipelines
Authors: Dugstad Arne , Seiersten Marion 
Published: December 2007

Abstract
The pH-stabilisation method is a cost effective, reliable and environmental friendly way to control corrosion in gas/condensate pipelines where glycol is used as hydrate preventer. Increasing the pH to 6.5-7.5 facilitates the formation of a protective iron carbonate film on the steel surface and reduces corrosion of the steel.
The carry-over of formation water puts limits on the use of the pH stabilisation technique as carbonate scale may form. Scale formation in glycol carrying pipelines is not easy to predict, as solubility data for CO2 and scale forming compounds in glycol solutions are very scarce. Glycol affects scale formation by changing the solubility and the precipitation kinetics, and the solubility of for instance calcium carbonate is markedly reduced.
The paper reviews the experience from the fields that have been pH stabilised and discuss the various pH-stabilisation methods that have been used. The paper gives data on the application limits with respect to formation water and discuss operational problems, challenges and solution related to the risk for scaling downstream the lean MEG injection point, in heat exchangers and in the MEG regeneration and reclamation systems.