bluuebunny/crossref_metadata_2025 huggingface dataset:
An Innovative Approach to Development Drilling in Deepwater Gulf of Mexico
Authors: Watson Pat , Kolstad Eric , Borstmayer Richard , Pope Tom , Reseigh Andy
Published: December 2007

Anadarko Petroleum's Marco Polo development is located in approximately 4,300 ft. of water in Green Canyon Block 608, in the central Gulf of Mexico (GOM). The discovery and appraisal wells were drilled in 2000, and the field will ultimately be produced using a tension leg platform (TLP).

The development drilling, which will be complete by 1st Quarter 2003, uses several innovative approaches to maximize project value. Some of the approaches challenge current industry trends and will be highlighted in this paper.
The Development and Application of Environmentally Acceptable Thermal Insulation Fluids
Authors: Dzialowski Andrew , Ullmann Holger , Sele Arne , Oosterkamp Ljiljana Djapic
Published: December 2007

Production from fields developed in deeper and colder waters requires that the hydrocarbons brought to the surface be at the highest possible temperature to eliminate asphaltenes, paraffins and hydrates from blocking a production line. Good insulation allows a less viscous fluid to be produced at higher rates, extend shut-in period and reduce stress during expansion and contraction of pipes. Ideally, the annular space between the riser and production line should be isolated with a special, low thermal conductivity fluid. Further, the insulation fluid must be environmentally acceptable to mitigate the effects of any spills or other unexpected events.

The recent development of a lightweight hybrid riser for a deepwater completion in North Sea required a thermal insulation fluid that was both cost effective and environmentally acceptable.

This paper describes a unique joint project to develop a lightweight riser and insulating fluid. The development included the building of a special test facility, which featured a 20-m long (60 ft) full size aluminum riser with electrically heated production pipe, which was filled with insulation fluid. The test piece was immersed into the sea for several months exposure.

The authors will detail several formulations, both mineral oil and water-base fluids including simple techniques to measure thermal conductivity, diffusivity and heat capacity. These data are compared to a specially developed computer model and field data from long-term exposure test. Other applications of the thermal fluid is drilling through permafrost and insulating transportation lines.
Summary of Results from a Joint Industry Study to Develop an Improved Methodology for Prediction of Geopressures for Drilling in Deep Water
Authors: Bridges James W.
Published: December 2007

This paper summarizes some results from a joint industry project organized through the Drilling Engineering Association to develop an improved methodology for pre-drill pore pressure and fracture gradient prediction for wells in deep water. The project known as DEA 119 was sponsored by Chevron and funded by a group of 21 organizations that included oil and gas operating companies, service companies and government organizations. Phase 1 of DEA 119 began in early 1999 and was completed in November 2001. Phase 2 began thereafter and is scheduled for completion in late 2003. This paper will provide an overview of the project and summarize some of the findings. Project activities ranged from industry surveys and in-depth reviews of various models and methods to detailed geopressure analysis of 100+ deep water Gulf of Mexico wells using a wide variety of approaches. Results from Phase 1 of the project were documented in a 300+ page best practice manual and a five day training course as well as a sizable database that includes analysis results and input data for the wells used in the project. Based on the consensus of participants, the project was limited to the Gulf of Mexico and geologically similar areas in other parts of the world. Virtually all the well data submitted by project participants was from the Gulf of Mexico. An argument can be made that the results are broadly applicable to geologically similar regimes in other parts of the world, i.e. deltaic basins with reservoirs in relatively young geologic strata that have undergone fairly rapid deposition. Phase 2 of the project is focused on further utilizing the database built in Phase 1 along with additional geologic and seismic data to construct geopressure models for several deepwater basins in the Gulf of Mexico and also to develop an improved methodolgy for fracture gradient prediction in deep water wells.
Plan for Surprises: Pore Pressure Challenges during the drilling of a Deepwater Exploration Well in mid-winter in Norway
Authors: Doyle Eamonn F. , Berry John R. , McCormack Niall J.
Published: December 2007

In the winter of 2001–2002 BP drilled the Havsule exploration well in 1495m of water offshore Mid-Norway. The efficient and safe drilling of the well was a major challenge due to a series of unknown factors including pore pressure. It was therefore necessary to plan and drill the well with a wide range of outcomes in mind and be prepared to adjust plans during drilling operations. With a particular focus on pore pressure, this paper describes how the well was planned and drilled to account for the uncertainties involved in drilling an exploration wildcat far out in the basin and a long way from any other well.

Some of the challenges were: Deepest water well so far in Norway.One of the worst winters in recent years.A gigantic submarine slide 8000 years ago that removed several hundred meters of sediment, increasing the uncertainty concerning pore pressure, fracture and overburden gradients.Uncertainty in the lithology.

During well operations there was a high focus on monitoring the pore pressure. Annular pressure and formation pressure were monitored as drilling progressed and pressure prediction models were continuously updated.

The results show that careful objective setting, planning, teamwork and implementation can help to achieve results even in difficult conditions with large uncertainties.
Closed Hole Circulation Drilling: Case Study of Drilling a High-Pressure Fractured Reservoir - Tengiz Field, Tengiz, Republic of Kazakhstan
Authors: Sweep M. N. , Bailey J. M. , Stone C. R.
Published: December 2007

The drilling of a sour, high-pressure fractured reservoir in the Tengiz field of Kazakhstan displayed complex and hazardous well control situations. While drilling the carbonate reservoir termed Unit 1, multiple fractures were encountered resulting in severe lost circulation followed by hydrocarbon influx into the well-bore.

Severe and uncontrollable lost circulation in the target reservoir prompted the use of special practices and equipment; thereby enhancing the safety and efficiency in the development drilling of the field.

A rotating control device (RCD) was employed to drill ahead blind (no fluid returns) by pumping a sacrificial fluid (water) down the drillpipe. Simultaneously, a pressurized mud-cap on the annulus with weighted oil based mud OBM controlled hydrocarbon influx. The overall process of pressurized mud-cap drilling will be described by the term Closed Hole Circulation Drilling (CHCD).

The successful application of CHCD has resulted in Tengiz well T-7252 being the first well to completely penetrate Unit 1 where lost circulation could not be controlled by conventional methods. After all Unit 1 fractures had been penetrated, a liner was installed to isolate the fractures using the same CHCD well control procedures employed while drilling the interval.

This technical paper will describe the process used to successfully plan, develop, and implement the CHCD technique in the Tengiz field.
Characterization of Blowout Behavior in Deepwater Environments
Authors: Adams Neal , Economides Michael J.
Published: December 2007

Offshore petroleum activities are likely to emerge as the next and clearly the most formidable technological challenge in the international petroleum industry. Both the size of the potential resource and the anticipated productivity of offshore oil and gas reservoirs will dwarf the behavior of even the most prolific presently on line petroleum resources. In accessing these reservoirs problems associated with on-shore or shallow offshore formations take a different hue.

Blowouts in water depths to 10,000 ft have certain potential ramifications not currently understood. Work has been done by several investigators to analyze blowout plume behavior, particularly with a view towards buoyancy and centerline plume wandering in the region immediately below sea level. To date, a more comprehensive reservoir-to-sea level study has yet to be undertaken and reported in the literature.

This paper reports on results from work to characterize blowout behavior in deepwater environments. The initial effort was to use reservoir and phase behavior modeling to determine mudline flow rates under worst-case conditions. MMS data from deepwater, Gulf of Mexico reservoirs was used to establish reasonable parameter boundaries. Normal and abnormal pressures were investigated, separate oil and gas blowouts were studied; wellbore diameters up to 14 inches were evaluated as some operators are currently contemplating using this bore size.

Results from the reservoir model were entered in plume modeling calculations prepared for this work. The model allows multiple crosscurrent studies as well as temperature modeling from the mudline to sea level. Again, separate oil and gas runs were made.

In some cases, these results followed intuitive expectations. Other scenarios rendered unanticipated findings. Specific conclusions include (1) identification of some reservoir and fluid systems that have little capacity to flow, even under an open flow scenario, (2) typical cross-current conditions do not seem to have a pronounced effect on the plume centerline at sea level and (3) oil blowouts have noticeably different characteristics than gas flows.
Well Control Procedures for Dual Gradient Drilling as Compared to Conventional Riser Drilling
Authors: Schubert J. J. , Juvkam-Wold H. C. , Choe J.
Published: December 2007

In order to meet the world's increasing demand for energy, petroleum producing companies must search for oil and gas in increasingly hostile environments. One area that shows great promise is in the deep water areas of the U.S. Gulf of Mexico. This is evidenced by increased lease sales and drilling activity that has occurred there within the last few years. As drilling moves into deeper waters, new technologies must be developed for safe and successful operations.

Beginning around 1996 four projects were begun to develop dual gradient drilling, DGD, technology for use in water depths greater than 5000 ft. The four projects are Shell Oil Company's project1, the SubSea MudLift Drilling Joint Industry Project2, SMD, the Deep Vision project3, and Maurer Technology's Hollow Glass Spheres project4. Several publications have discussed the advantages that dual gradient drilling technology has over conventional deepwater drilling in the ultra-deepwaters.5,6,7

Although the advantages of the dual gradient projects are well documented, there has been little published on one of the major concerns expressed by all four projects. That is, how will well control differ for dual gradient drilling as compared to conventional riser drilling?6,8,9 This paper reports on a comparison of the well control aspects of dual gradient drilling to those of conventional riser drilling. It is based upon the work that the authors performed as part of the SMD project.
Understanding Formation (In)Stability During Cementing
Authors: Heathman J. , Tare U. , Ravi K.
Published: December 2007

Managing formation (in)stability should be an integral part of well construction from drilling through cementing and completion operations. Formation (in)stability while drilling has been recognized and is an ongoing study in the petroleum industry. Most of the emphasis in these studies has addressed the interactions between drilling fluids and formations, as well as, the geomechanical aspects. However, if the wellbore is stable at the end of the drilling phase, but the cement and spacer properties are not optimized accordingly, the formation could be destabilized during cementing. Such an event could negate much of the prior effort toward controlling instability. Destabilization could adversely impact the well construction and overall field development throughout the well's lifecycle.

As the rock material is removed and replaced by a drilling fluid and subsequently displaced by cementing fluids (spacer and cement slurry), stability of the wellbore should be ensured by applying an adequate net radial support to the formation. The borehole pressure exerted by these fluids can counteract the near-wellbore effective stress concentration created while drilling. If the radial support applied to the formation is inadequate, the stress concentration can exceed the formation compressive strength, leading to borehole collapse. On the other hand, excessive borehole pressure can lead to lost circulation problems if the near-wellbore tangential (circumferential) stress and the formation tensile strength are exceeded. As the formation is exposed to drilling and cementing fluids, the near-wellbore effective stress concentration is altered because of the formation fluid's physicochemical interaction. Such alteration of the effective stresses and formation properties can result in time-dependent stability problems.
Washout of Cr(III)-Acetate-HPAM Gels from Fractures
Authors: Seright R. S.
Published: December 2007

This paper investigates washout of mature Cr(III)-acetate-HPAM gels from fractures. After gel placement, the pressure gradient for gel washout during brine or oil flow was similar to the pressure gradient observed during gel placement. The mechanism of gel failure involved the displacement of relatively mobile gel from wormholes. Generally, only a small fraction of the gel (<5%) was displaced during the washout process. Resistance to washout can be increased by injecting a more concentrated gel. However, this approach exhibits significantly higher pressure gradients during gel placement.

The presence of a constriction in a fracture inhibited gel washout during the first pulse of brine flow after gel placement. However, during subsequent brine flow, gel erosion occurred upstream of the constriction to the same extent as downstream. The extrusion, leakoff, and washout behavior in fractures in strongly oil-wet polyethylene cores were similar to those in strongly water-wet Berea sandstone.

Gel washout can be reduced by controlling gel placement rate. A Cr(III)-acetate-HPAM gel placed in a 0.04-in. wide fracture at 826 ft/d was about five times more resistant to washout than a gel placed at 4,130 ft/d. Gel washout can also be reduced using secondary crosslinking reactions. Post-placement reaction with Cr(III) acetate increased resistance to washout for a resorcinol-formaldehyde-HPAM gel by a factor from two to three.

During steady state flow after first breaching the gel, a Cr(III)-acetate-HPAM gel reduced permeability to water (within the fracture) moderately more (2.5 to 4.7 times) than that to oil. Disproportionate permeability reduction in fractures was most evident at low flow rates.
Polymer Design for Relative Permeability Modification Treatments at High Temperature
Authors: Chiappa Luisa , Andrei Maria , Lockhart Thomas P. , Maddinelli Giuseppe , Burrafato Giovanni , Pitoni Enzo
Published: December 2007

Previous studies have shown that cationic polyacrylamides are particularly effective agents for selectively reducing the permeability of treated rock to water. This ability depends on several factors, but a key role is played by the cationic functionality, which anchors the polymer to the rock. It is shown here that the applicability of these treatments to higher temperature is severly limited by the tendency of the cationic group (above 50°C) and the polyacrylamide backbone (above 70°C) to undergo hydrolysis. A general chemical strategy is outlined for overcoming these two effects, and two new families of cationic, high molecular weight polyacrylamides are reported which display excellent stability to 70°C and 100°C, respectively. These polymers demonstrate excellent relative permeability modification properties in laboratory tests, a result which has been confirmed in the field in a dry gas well treatment.
Effect of Flow Rate on Disproportionate Permeability Reduction
Authors: Ganguly S. , Willhite G. P. , Green D. W. , McCool C. S.
Published: December 2007

Disproportionate permeability reduction (DPR), in which water permeability is reduced to a much greater extent than oil permeability, has been observed in a number of polymer gel systems. Although several different mechanisms have been proposed, no one mechanism has been generally accepted. In the study reported here, the focus was on the effect of flow rate on DPR by varying the pressure gradient. Polyacrylamide-chromium acetate solutions were allowed to gel in Berea sandstone rocks. Flow channels were then developed by dehydration of the gels by flowing oil or water at a specified pressure gradient. After dehydration was complete, water and oil displacements were successively conducted over a wide range of pressure gradients, always maintaining the pressure gradient at a value equal to or less than the pressure gradient used for dehydration. Oil saturation of the rock was monitored from analysis of the effluent and the use of a tracer in the oil phase. The saturation profiles in some of the rocks were obtained from microwave scans at various stages of the experiment. Permeabilities and residual resistance factors at residual saturations were calculated and reported as a function of pressure gradient. RRF values for brine decreased by an order of magnitude upon increase in pressure gradient. RRF values for oil, however, decreased to a much less degree over the same increase of pressure gradient. At high pressure gradients, DPR diminished in one set of experiments. The variation of permeability with pressure gradient demonstrates that the gel structure is elastic and deforms when pressure gradient changes. The results were compared to literature data and it was found that rate effects were generally present in previously reported work.
Starch-Lubricant Compositions for Improved Lubricity and Fluid Loss in Water-Based Drilling Muds
Authors: Sifferman Thomas R. , Muijs Herman M. , Fanta George F. , Felker Frederick C. , Erhan Selim M.
Published: December 2007

Development of water-based mud systems that approach the performance of oil-based muds is an ongoing effort. Starch-lubricant compositions were developed as environmentally safe, non-toxic, stable dispersions in water-based drilling muds. Starch-lubricant compositions were prepared by jet cooking mixtures of water, starch, and lubricant to produce aqueous starch dispersions containing suspended lubricant droplets 1-10 microns in diameter. These droplets do not separate or coalesce. The dispersions were drum dried and milled to dry, non-oily powders containing 28% lubricant by weight.

These dry powders were then tested at 5 lb/barrel in laboratory-prepared lignosulfonate drilling muds. Various commercial olefins, esters and/or polybutenes were evaluated as lubricants. Standard laboratory tests indicated that starch-lubricant compositions lowered both API and HTHP fluid loss values. More importantly, coefficient of friction values were 12-25% of the untreated base mud and were similar to the average values for oil-based muds. Muds formulated with starch-lubricant compositions usually contained only 0.5% lubricant (v/v), yet performed better than a typical field mud control containing 3% lubricant (v/v).

These exceptionally good results with one-sixth the amount of a typical lubricant suggest that the size and distribution of lubricant droplets achieved in these systems may enhance lubricant efficiency. Therefore, further investigation of such formulations is warranted, including a field test to evaluate the advantages of this newly-patented technology.
Large Scale Laboratory Investigation of Corrosion Inhibitor Containing Emulsion Placement in Wells
Authors: Sanghvi Gautam J. , Garcia David A. , Civan Faruk , Shaw Thomas M. , Campbell Samuel E. , Bartrip Keith A.
Published: December 2007

Accurate placement of emulsions containing formulated inhibitors in the casing-tubing annulus can provide more effective and long term well treatment than the standard batch methods. This paper presents the results of experimental investigation and correlation of experimental data based on a large-scale model well constructed to simulate flow within the typical well annulus. The wellhead and bottom hole assemblies were designed to closely simulate those found in producing oil and gas fields.

Various chemicals were injected at the wellhead to flow through the annulus, to determine the role of viscosity, density, and surface tension, which were then followed by brine flush. The flow of emulsion and flush through the annulus was recorded at fixed positions and with mobile cameras. The observation and identification of the flow patterns during the treatment was made. A set of pins was inserted into the casing wall. This allowed the measurement of thickness of the emulsion coating the annular surface. The surface area coated by the emulsion was traced and measured. Downhole emulsion delivery was thus determined by performing the emulsion material balance. The amount of emulsion retained in the system is based on deposited chemical thickness, coated surface area and concentration of chemical in the annular fluids after the tests.

The results were correlated using dimensionless groups to allow extrapolation to well depths encountered in a typical oilfield production. The effectiveness of emulsion delivery and the flow patterns in the annulus were determined to strongly depend on the application type and conditions.
Barium Sulphate Inhibition in Subsea Systems – The Impact of Cold Seabed Temperatures on the Performance of Generically Different Scale Inhibitor Species
Authors: Laing N. , Graham G. M. , Dyer S. J.
Published: December 2007

Inorganic precipitates (scales) are one of the major flow assurance concerns in offshore oil and gas production, and lead to significant reductions in productivity and costly workovers if allowed to form uncontrolled. Scale prevention by the use of chemical inhibitors, applied either by continual injection or by squeeze treatment into the near wellbore formation, has generally been regarded as the most cost effective solution to the problem. The increased development of subsea satellite production brings with it a number of additional challenges to the chemical control of inorganic scale. The requirement to control scale at low seabed temperatures (4 - 5°C) over long residence times presents a particular challenge.

This paper examines the performance of three generically different scale inhibitor species including a polyvinyl sulphonate (PVS), a phosphino polycarboxylate (PPCA) and a penta phosphonate (DETPMP) under typical North Sea Scaling conditions. The relative performance of the different inhibitor species against Barium Sulphate scale is compared at temperatures between 5°C and 5°C and up to 22 hours residence times.

Results show that the performance of different inhibitors are significantly affected and to different degrees as a function of temperature, and that this is not simply related to changes in supersaturation against barium sulphate precipitation. The performance of the phosphonate species DETPMP is significantly reduced at lower temperatures and this is related to reduced adsorption at the barium sulphate surface. However the performance of the PVS is significantly improved, indicating that such species offer the potential for improved scale control at lower seabed temperatures. PPCA is only marginally affected by reduced temperatures in a manner more consistent with the increased supersaturation against barium sulphate.
Investigation of Wettability Alteration Following Scale Inhibitor Adsorption onto Carbonate and Clastic Reservoir Core Material – Static Tests and ESEM Studies
Authors: Guan H. , Graham G. M. , Juhász A.
Published: December 2007

In this paper, we make an assessment and comparison of scale inhibitor/rock interactions onto carbonate (calcium carbonate and dolomite) and clay-rich (illite-rich and kaolinite-rich) core materials. This is compared using both non-solvent cleaned and solvent cleaned (increased water wetness) reservoir chips of the same core material. In order to investigate the wettability alteration following the interaction with scale inhibitor solutions, ESEM studies were carried out on the pre- and post treatment reservoir chips.

The interaction of two generic scale inhibitor chemicals penta-phosphonate (DETPMP) and phosphino-polycarboxylic acid (PPCA) with various un-cleaned and solvent-cleaned core substrates at pH 2 and pH 5.5 have been examined under static conditions. The bulk differences in the inhibitor-rock interactions have been assessed by the comparison of cation (Ca, Mg) and scale inhibitor (SI) concentrations of pre- and post treatment core chips. ESEM observations and EDAX analysis of the pre- and post treatment core chips have then allowed for the investigation of wettability alteration following the interaction with various scale inhibitor solutions.

In summary, quite distinct inhibitor/rock interactions and wettability alterations are observed at different mineral surfaces. Under certain conditions, excessive surface precipitate of pseudo scale (inhibitor/calcium complex) can occur as a result of mineral dissolution and consequential localized increase in pH and cation concentration. In addition, the adsorption/precipitation of SI onto certain minerals under specific conditions have been found to reverse the original wettability state of the reservoir chips. The results therefore help to explain relative permeability issues associated with scale inhibitor treatments both in core flood experiments and field treatments. Moreover, the hot solvent cleaning process has made the initial mineral surface more water wet.
Boosting the Heating Capacity of Oil-Production Bundles Using Drag-Reducing Surfactants
Authors: Sletfjerding E. , Gladsø A. , Elsborg S. , Oskarsson H.
Published: December 2007

Insulated and heated pipe bundles are frequently used in sub sea oil production systems to avoid low oil temperatures. To boost the heating capacity of the 10 km long pipe bundle from the Gullfaks South field in the North Sea, a surfactant based DRA was developed. The DRA was injected in the 20 km long heating medium loop in July 2001, and after over 12 months of operation the DRA gives over 50 % increase in the heating medium flow rate. The surfactant has effectively reduced the pressure drop in the heating medium circulation loop resulting in an increase in the flow rate and in the bundle heating capacity.
Development of a Set Retarder for Foamed Cement Applications
Authors: Chatterji J. , Crook R. J. , Lebo S. E. , Resch S. L.
Published: December 2007

Due to a recent resurgence in foamed cement utilization, there is a need for an additive that can provide adequate set retardation without affecting the foam characteristics of the cement system. This paper details the development of a foamed cement retarder comprising a blend of lignosulfonate, kraft lignin and a pentose sugar. Laboratory studies have shown that the performance of this product exceeds that of conventional set retarders with regard to maintaining the stability of the foamed cement system. This set retarder can also function in non-foamed applications. Several wells have been successfully completed using this new technology and case histories will be provided.
New Opportunities for the Drilling Industry Through Innovative Emulsifier Chemistry
Authors: Patel Arvind , Ali Syed
Published: December 2007

As the drilling industry operates in more stringent environmental constraints and conservative economical environment, the industry is poised to take advantage of innovative emulsifiers for new opportunities in solving the environmental problems and offer economical advantages over conventional invert emulsion drilling fluids. We have developed various innovative invert emulsion drilling fluids using novel emulsifiers. These systems provide a quantum leap in new drilling fluid technology in solving environmental problems while offering economical advantages over conventional invert emulsion drilling fluids.

Since, the inception of invert emulsion drilling fluids decades ago, emulsifier technology for these systems has not advanced much. The focal points in development in past history have been in base fluids, O/W ratios and some in weight materials, however very little has been changed in emulsifier chemistry. Only step-changes in technology have been achieved with changes in base-fluids and other parameters of invert emulsion drilling fluids. It is time to move on. Using innovative emulsifier chemistry has produced novel invert emulsion fluids, which address the environmental as well as performance and cost-related issues in drilling operations.

This paper discusses the systematic design, development and testing of novel emulsifiers for innovative invert emulsion drilling fluids. The overall impact of manipulation of emulsifier chemistry in invert emulsion drilling fluids to meet the environmental and functional requirements of drilling operation is presented. The formulations and applications of lime-free high temperature invert emulsion drilling fluid, negative alkalinity ester-based fluid, and reversible invert emulsion drilling fluids in laboratory experiments as well as field trials are highlighted.
Deployment of Emulsified Scale – Inhibitor Squeeze to control Sulphate/Carbonate Scales within Subsea Facilities in the North Sea Basin
Authors: Jordan M. M. , Murray F. , Kelly A. , Stevens K.
Published: December 2007

This paper presents laboratory/field results and lessons learned from a North Sea field where a novel emulsified scale inhibitor was deployed via bullhead squeeze treatments in four low water cut, sand screened wells. The field is a subsea development within the UK sector of the North Sea. These were the first squeeze treatments to be performed on the field.

The remote location of the production wells relative to the production vessel and their high production levels meant that scale management was critical to the effective recovery of hydrocarbon from the field. The risk of scale formation even at low water cut was deemed sufficiency high for a scale inhibitor squeeze application to be applied.

The decision to use emulsified scale inhibitor for treating such low water cut wells was arrived at after an extensive series of laboratory tests including formation damage coreflood studies and assessment of chemical retention. The risk of fines mobilisation when deploying water based chemicals in low water cut, poorly consolidated reservoir will be outlined.

The challenges with the deployment of the chemical package via a diving support vessel (DSV) and gas lift line will also be outlined along with the performance of the wells following the treatment and the effectiveness of this scale control method.

This paper will outline in detail the particular issues associated with chemical injection to a subsea facility, many of which are currently being developed in the Gulf of Mexico and is a good example of lessons learned and sharing best practice from another oil basin.
The Impact of Dissolved Iron on the Performance of Scale Inhibitors Under Carbonate Scaling Conditions
Authors: Graham G. M. , Stalker R. , McIntosh R.
Published: December 2007

The laboratory determination of scale inhibitor (SI) performance under field specific conditions using dynamic or static scale inhibitor tests provides an important method for determining minimum inhibitor concentrations (MIC's) for the inhibition of scale growth. This paper will discuss the ability of small amounts of ferrous iron to dramatically reduce the ability of SI's to inhibit calcium carbonate scale formation under dynamic laboratory test conditions. It has been previously reported that the presence of ferrous ions has an inhibiting effect on calcium carbonate formation under dynamic test conditions, which was confirmed for the brine systems used in this study. However, despite the somewhat milder scaling regime in the presence of ferrous ions, addition of Fe2+ ions to test brines caused the observed MIC's of typical scale inhibitor chemicals to increase more than one hundred fold when tested against calcium carbonate scale. A much less dramatic reduction in SI performance in the presence of ferrous ions was observed for barium sulfate scale formation under dynamic test conditions.

Such interference in inhibitor performance can have major implications for the field application of scale inhibitor chemicals, leading to unexpected decline in production. The presence of ferrous ions has been shown to adversely affect scale inhibition of a number of different classes of SI chemicals, including poly(vinylsulphonate) (PVS) which has previously been reported as being iron-tolerant. This paper will describe the results of laboratory studies into this phenomenon, in which the nature and scope of the interference were investigated.
Scale Formation And Prevention In The Presence Of Hydrate Inhibitors
Authors: Tomson M. B. , Kan A. T. , Fu G. , Al-Thubaiti M.
Published: December 2007

Hydrate formation can be a serious problem in many gas production systems. Large volumes of hydrate inhibitors (e.g., methanol, ethanol, ethylene glycol, and triethylene glycol as cosolvent) are often added to control hydrate formation. Such practice has an adverse effect on scale formation since the mineral salts are generally less soluble in the cosolvent. Due to production from reservoirs oilfield brines are often close to saturation as they enter a well, and even a small amount of added methanol, ethanol, etc., is often sufficient to induce various minerals to precipitate. The scaling tendency of sparingly soluble mineral salts, e.g., calcite and barite, in methanol/brine and ethanol/brine solutions is observed to be orders of magnitude larger than in the brine alone. Halite scaling is also severely affected in the presence of methanol or ethanol. Ethylene glycol and triethylene glycol have a lesser adverse effect on mineral salt scaling tendency. There is no accepted methodology to correlate the effects of hydrate inhibitors on scale formation as there is for electrolytes. Similarly, the effect of hydrate inhibitor on scale inhibition with common inhibitors is not well known. In this paper, a semi-empirical approach is proposed to correlate the effect of hydrate inhibitors on scale formation and inhibition from experimental solubility measurements of halite, barite, gypsum, calcite and carbonate equilibrium chemistry. The ion-cosolvent activity coefficients can be used directly in any solution speciation code to evaluate the effect of cosolvent on mineral scale formation. The validity of the equation has been tested between 4-50 °C and 1-6 M ionic strength. Working equations that can be used in gas and oil production to calculate the effect of cosolvents on scale formation will be presented. Such equations have been incorporated into ScaleSoftPitzer V.4.0. ScaleSoftPitzer™ is a Microsoft™ Excel™ based program to predict scale tendency, specifically written for the oil and gas production systems. Details of using ScaleSoftPitzer V.4.0 to predict hydrate inhibitor induced scale formation and case studies will be presented. Initial tests of scale inhibitor efficiency in methanol will also be presented.
Effect of Rock Type and Acidizing Additives on Acid Reaction Rates Using the Rotating Disk Instrument
Authors: Taylor K. C. , Al-Ghamdi A. H. , Nasr-El-Din H. A.
Published: December 2007

This work uses a rotating disk instrument to measure dissolution rates of both calcite and dolomite rock samples. Results of more than 60 experiments are reported in this paper. The effect of common acidizing additives on the acid dissolution rate is measured for different acids containing quaternary amines, polymer, surfactant, mutual solvent, iron chelating additive, and dissolved iron.Measurements are made at 23 and 50 °C for calcite marble and dolomite marble samples.

Marble samples from Turkey, Greece and Italy were analyzed to find suitable reference materials.Marble composed of 100% calcite (calcite marble) as well as 91% dolomite (dolomite marble) was used and compared very well with previously published results.Results of acid dissolution rates with common acidizing additives showed significant differences. 1.5 vol% cationic acrylamide polymer decreased the calcite and dolomite dissolution rates significantly. At 1000 rpm the calcite dissolution rate with 1.5 vol% polymer and 0.1N HCl had a value that was 11.4% of the value measured with 0.1N HCl alone.Polymer changed the acid-rock reaction from mass transfer limited to surface reaction limited with both calcite and dolomite. This is a surface effect possibly due to polymer adsorption.10 vol% mutual solvent increased the acid dissolution rate by 9% for calcite and by up to 29% for dolomite.5,000 mg/L iron (III) resulted in surface deposition of iron (III) hydroxide. At low rotational speeds, this surface layer had an inhibiting effect on dissolution rate for both calcite and dolomite.2 vol% corrosion inhibitor decreased the calcite dissolution rate by approximately 9%.Citric acid at 12 g/L decreased the dissolution rate of calcite by an average of 9%, possibly due to the formation of calcium citrate at the surface.0.2 vol% nonionic surfactant had no significant effect on acid dissolution rate of calcite.
Prediction and Scaleup of Waxy Oil Restart Behavior
Authors: Borghi G. -P. , Correra S. , Merlini M. , Carniani C.
Published: December 2007

A major concern in the design of offshore pipelines is flow restart of waxy oil after a planned or emergency shut-down. As the offshore oil industry encounters increasingly challenging production environments, such as in deepwater or marginal fields, more accurate restart predictions are a requirement for reducing CAPEX and guaranteeing flow assurance. The present state-of-the-art does not generally provide reliable predictions of the pressure required to restart flow in a gelled pipeline; laboratory measurements tend to overestimate the restart pressure, so that empirical factors are used to scale the laboratory data to field conditions. Based on a series of experimental measurements carried out in a upgraded model pipeline, our analysis suggests that compressibility and the appearance of a solid-like fracture at the front of the propagating pressure wave have to be taken into account in order to better model the cold restart process.
A Thermochemical Process for Wax Damage Removal
Authors: Rocha Nelson O. , Khalil Carlos N. , Leite Lúcia C.F. , Bastos Roberto M.
Published: December 2007

Relevant declines in oil production on several Reconcavo Basin wells (NE Brazil) have been observed as a result of wax deposition phenomena. Evidences indicate several points of wax obstruction, such as: reservoir rock, perforations, casing annulus, tubing and production lines.

The process consists on the injection of an emulsion formed by an aqueous solution containing nitrogenated salts, an organic non-polar solvent and a viscoelastic polymer. When the mixture is placed in the annulus, a strongly exothermic chemical reaction occurs, generating a high quality stable foam. The penetration radius of the foam into the porous media is enough to assure sufficient wax removal and induce immediate production enhancement. During well depressurizing, nitrogen gas, an aqueous saline phase and an organic mixture containing wax and the solvent are recovered. All the reaction products are environmental friendly.

This paper presents lab and field results of this workover method based on in situ thermal generation of foam. Lab studies include foam formulation optimization aiming maximum wax deposit removal in several reservoir conditions. Field implementation includes the analysis of production enhancement in 10 wells in the area where the technique has been applied.
Low-Dosage Hydrate Inhibitors (LDHIs): Reducing Costs in Existing Systems and Designing for the Future
Authors: Frostman L. M. , Thieu V. , Crosby D. L. , Downs H. H.
Published: December 2007

Hydrates remain a significant flow assurance issue in nearly every Deepwater development. Traditional hydrate control methods of insulation and/or thermodynamic chemical inhibition may not provide the desired level of hydrate protection at an economic price. Low-Dosage Hydrate Inhibitors (LDHIs) are a proven technology to control hydrates in numerous applications and are instrumental in reducing the total cost of operations (TCO). In particular, LDHIs offer solutions to existing problems such as unexpected water breakthrough, undersized methanol injection capacity, and high-volume methanol transportation / storage limitations. As an added benefit, it is possible to co-formulate LDHIs with other production chemicals, such as paraffin and corrosion inhibitors, and thus minimize the number of chemical injection lines. While the benefits to existing developments are appreciable, the true potential of this technology lies in the reduced capital expenditures (Cap Ex) required for systems designed specifically for LDHIs. Potential savings include, smaller umbilical line diameters, the elimination of a methanol wash and recovery operation, fewer umbilical lines, smaller / lighter storage capacity, and smaller pumps.
Application of Novel Diversion Acidizing Techniques To Improve Gas Production in Heterogeneous Formation
Authors: Wang Xugang , Zou Honglan , Tian Jun , Zhang Fuxiang , Cheng Xingsheng , Li Suzhen
Published: December 2007

The aims of this study were to design a novel diversion acidizing stimulation treatment to remove formation damage and enhance gas production in a recently exploring ultradeep heterogeneous sandstone gas fields in TARIM, while avoiding formation collapse.

Although foam can be used to divert acid from the chief zones to the damaged zones, it is not available in this kind of ultradeep abnormally high pressure gas field and an additional handling equipment is required. In this paper a new diversion technique from both laboratory testing and field monitoring is discussed in detail. Laboratory testing conducted in a dual-core flow apparatus showed excellent diversion from a high-permeability formation to a low permeability one by using viscosity system. Field case histories in the heterogeneous gas formation in TARIM over past three years are presented. The field cases histories show the success of diversion acid technique and the improvement of gas production significantly.
Real-Time and In-Situ Detection of Calcium Carbonate Scale in a West Texas Oilfield
Authors: Smith J. K. , Yuan M. , Lopez T. H. , Means Mitch , Przybylinski John L.
Published: December 2007

A novel technique has been developed to detect the onset and increase of calcium carbonate scale deposition from oilfield production fluids. This method utilizes an attenuated total reflectance (ATR) probe, called the scale sensor, to detect scale formation in-situ. Because this method is based on existing technology and requires little supporting equipment, a simple cost-effective monitoring device could be placed in many locations within a production system. This method could provide a system wide, in-situ, real-time response to calcium carbonate scale formation at its earliest stages.

As a first step towards evaluating the effectiveness of this new technology, the scale sensor was field tested at a west Texas oilfield. The scale sensor was observed to detect the deposition of calcium carbonate under static and flowing conditions in actual produced fluids. In the static tests, crude oil, suspended solids and other endogenous materials did not affect the scale sensor response. Under flowing conditions, like those found in the production flow lines at the west Texas oilfield, scale sensor response was observed to correlate to the chemical injection rate of both the scale inhibitor and dispersant. Based on the results from the scale sensor, the scale inhibitor injection point will be moved to the wellhead shortly.
Scale Prediction and Remediation for Deep Water Fields
Authors: Bezerra Maria C. M. , Rosario Francisca F. , Rocha Anderson A.
Published: December 2007

Completion technologies for horizontal and subsea deep-water wells have been developed to make feasible and increase oil production.

Horizontal and subsea wells in Petrobras are usually located at long distances from production facilities and in deepwater. Scale control can be implemented on these wells via bullhead treatment along a service line or down production lines.

The scale potential for deepwater fields from Campos Basin, Brazil, was assessed. Thermodynamic model predicted a moderate barium and strontium sulfate precipitation in production wells (down hole). More severe precipitation was predicted for the lower temperature of the risers (10 to 20°C). Despite of the predictions based on thermodynamic calculation, experimental work performed considering conditions of temperature, residence time and chemistry of produced water showed that precipitation is expected in reservoir rather than in the risers. Laboratory results agree with field data observation. Data from gamma ray log obtained in recent intervention caused by productivity loss in one well of these fields, showed that scale was formed in the production well (screen, gravel and reservoir) rather than in the flow lines. Chemical dissolution treatment was designed and applied in the wells from this field restoring their productivity.
Scaling Problems in Western Siberia
Authors: Voloshin A. I. , Ragulin V. V. , Tyabayeva N. E. , Diakonov I. I. , Mackay E. J.
Published: December 2007

Yukos Oil Company is the second largest oil production company in Russia, and produces 1.2 million barrels daily, with > 60% of this coming from fields in W. Siberia. Base oil and gas production units are located in the European part of Russia (OAO Samaraneftegaz) and W. Siberia (OAO Yuganskneftegaz and OAO Tomskneft VNK) [1]. This production comes from a variety of fields, and it is common for these fields to produce at significant water cuts. Produced water leads to several production and cleanup problems (since it is also re-injected), one of these being the problem of mineral scale.

The most common scale is calcium carbonate and this is found in both mild and more severe scaling cases. Sulfate deposits are present too in minimal amounts. However, a feature of the W. Siberian reservoirs is that they have many thousands of wells. Therefore, although the technical problem of treating a single well may not be large, the approach and logistics to protect such a large number of wells is a significant challenge.

In this paper we survey the problems of scale in these W. Siberian fields and we outline how Yukos has approached this challenge.