For HPHT wells it appears that the only industry practice for open hole sand control has been Stand Alone Screens (SAS), even for wells that should have been gravel packed. For North Sea HPHT field developments, SAS has been chosen as the open hole sand control method. However, according to company best practice, these wells should have been gravel packed. General skepticism around gravel packing for these wells is primarily based on the risk of losses. A study was initiated to look closely at potential losses during gravel pack pumping when compared to SAS in HPHT environment. Key issues:a. Narrow margin between pore pressure and fracturing gradient b. Well control risks, technical risks and cost c. Fluid selection The basis for the study was to perform gravel packing with conditions as close as possible to the planned low well angle SAS wells solution. The screens were to be run in screened reservoir drilling fluid. This fluid contains filtercake repair particles. It became natural to evaluate this fluid also as a carrier fluid for the gravel, thus mitigating the risk of losses. Due to small margin between pore pressure and fracture gradient, the gravel pumping operation would have to be planned to be performed at low rates. To qualify the HPHT gravel placement, yard testing was performed in a mini-scale gravel pack model. Gravel was placed successfully at low rates with screened reservoir drilling fluid. Very little degree of settling in horizontal surface lines was observed at low pump rates, hence no practical consequences is expected for this in high angle well sections. Furthermore, flowback testing in lab was performed on the particle containing carrier fluid. The major findings in this study were: --Gravel can be placed effectively at low rates, minimizing ECD impact in a narrow pore/frac operational window.--Gravel can be placed using screened formate based Reservoir Drilling Fluid (RDF) maintaining the filtercake intact and with minimum risk of losses. --The particle containing carrier fluid has no adverse effect on gravel pack permeability.

The rigorous environmental regulations of the North Sea oil and gas fields have required fundamental changes in the way service companies acidize wells. Traditionally, acid corrosion inhibitors have been some of the most toxic chemicals routinely pumped downhole. This paper describes a new acid corrosion inhibitor (NSACI) that meets the Norwegian environmental "Yellow" specifications for chemicals. This inhibitor functions in both mineral and organic acids and has been successfully used in the larger fields on the Norwegian Continental Shelf. Laboratory data is presented in detail along with field references to explain both the strengths and limitations of this new, environmentally-friendly acid corrosion inhibitor. Introduction Clean-up and stimulation of wells with acid is a technology over one hundred years old1. Hydrochloric acid is used to dissolve carbonate material from both the well tubulars (scale) and the formation (limestone/dolomite) itself. If a steel or formation is sensitive to HCl then organic acids such as acetic and formic acid are used for these same tasks. During the production of oil and gas carbonate scale is usually deposited from formation water high in carbon dioxide. As the pressure on this water lessens the dissolved carbon dioxide will effervesce. The loss of this CO2 results in a lowered solubility to carbonates allowing precipitates to form. Divalent iron and calcium are the two most common counter ions in this precipitate. The general formula is written as follows: CO2 + CaCO3 + H2O -» Ca(HCO3)2 Removal of this carbonate scale is economically achieved with either HCl acid, acetic acid or formic acid. Use of Hydrochloric Acid Hydrochloric acid is the most common acid used for scale removal and carbonate formation stimulation. As a common industrial side-product it is relatively cheap and readily available. In its most concentrated aqueous form it may be found at 37–38% by weight. When used to acidize a well it is cut anywhere from 28% down to 3% HCl. 15% HCl is commonly recommended when acidizing Norwegian sector wells, many of which have bottom hole temperatures under 200 oF. Any of these strengths will damage steel tubulars, especially as the bottom hole temperature and contact times climb. Hydrochloric acid is capable of dissolving up to 3.66lbs of limestone per gallon of HCl at a concentration of 28% by the reaction: 2HCl + CaCO3-» CaCl2 + H2O + CO2 Dolomite, which is a mixture of calcium and magnesium carbonate, reacts somewhat slower with hydrochloric acid by the formula: 4HCl + CaMg(CO3)2-» CaCl2 + MgCl2 + 2H2O + 2CO2 Use of Organic Acids Organic acids are used instead of HCl with some formations and tubulars where HCl cannot be used. For example, some sandstone formations will produce excessive fines or suffer other problems if acidized with HCl. Also, certain alloys such as chrome steels, brass and aluminum can be difficult to protect from the hydrochloric acid, especially at elevated temperatures. Formic and acetic acid are much weaker acids than HCl. However, the concentrations of the organic acid must be kept below 15% for acetic acid and under 10% for the formic acid to prevent precipitation of (CH3COO)2Ca and (HCOO)2Ca.

TX 75083-3836, U.S.A., fax 1.972.952.9435. AbstractThe need for an efficient displacement of drilling fluids from cased wells prior to installation of completion equipment has been relatively undisputed in the past.Several different fluid systems has been applied as well as a variety of different mechanical tools to achieve what is considered to be a clean well in order to safely run advanced completion equipment in the well. In contradiction to the requirements related to running more advanced equipment in the wells is the fact that several of the fields on the Norwegian shelf are entering the mature phase and tail end production. For these fields the margins are less and a significant focus is put on cost efficient solutions. In many cases, the need for casing cleaning in conjunction with displacement of drilling fluids is questioned.The current paper are reviewing in detail the results from drilling fluids displacement and cased hole cleaning operations performed on 192 wells on the Norwegian continental shelf over the six past years.These wells cover a variety of different completion scenarios where both water based and oil based drilling fluids have been utilised.The results from the survey are presented with a focus on the requirements towards a clean well and the ability to measure the efficiency of the different fluid systems and operational procedures utilised.The paper discuss different casing cleaning requirements versus well completion scenarios and displacement techniques.

Summary Formation damage has received significant attention over many years as one of the primary reasons for well productivity impairment, to the detriment of completion damage. The objective of this paper is to redress this imbalance and to focus on the significant contribution that completion damage has on well productivity. Formation damage is a reduction in inflow performance because of damage to the near wellbore, while completion damage is an increased pressure drop affecting the lower completion (e.g., plugging of sand screens and frac-packs). A completion damage classification system is presented for the first time that relates this damage type to the typical lower completion designs used by Equinor throughout well lifetime. In addition, a review of some of the fluid qualification tests involving completion damage either directly or indirectly has been performed to assess how representative these are. Computational fluid dynamics (CFD) was identified as a useful tool to assess how representative testing was. Fluid compatibility. CFD was used to determine the displacement efficiency from drilling to completion fluid in a candidate well, and hence the mixing ratio of drilling fluid to completion fluid to be used in compatibility tests. Furthermore, CFD simulations provided an indication of the likely shear rates occurring during displacement that were later used in the testing. Fluid stability. To determine the influence of sag on fluid displacement efficiency, CFD was used to model the worst-case situation where all the weighting agents came out of suspension. Using the displacement efficiency and shear rates obtained, a new dynamic completion damage test was devised to determine the potential for screen plugging as this is the most common lower completion used by Equinor. This test uses the same equipment as coreflooding except that the plug is removed, and a screen is inserted. Finally, an overview will be presented with recommendations of how Equinor’s approach to completion damage has changed because of this study, with an increased focus on achieving a better balance in the evaluation of formation and completion damage prior to the drilling and completion of wells.

Formation damage has received significant attention over many years as one of the primary reasons for well productivity impairment, to the detriment of completion damage. The objective of this paper is to redress this imbalance and to focus on the central role that completion damage has on well productivity. Formation damage is a reduction in inflow performance due to damage of the near wellbore, while completion damage is an increased pressure drop effecting the lower completion, e.g., plugging of sand screens. A completion damage classification system is presented for the first time that relates this damage type to lower completion design throughout well lifetime. In addition, a review of some of the fluid qualification tests has been performed. Fluid compatibility. Computational fluid dynamics (CFD) was used to determine the displacement efficiency from drilling to completion fluid in a candidate well, and hence the mixing ratio of drilling fluid to completion fluid to be used in compatibility tests. Furthermore, CFD simulations provided an indication of the likely shear rates occurring during displacement that were later used in the testing. Fluid stability. To determine the influence of sag on fluid displacement efficiency, CFD was used to model the worst-case situation where all the weighting agent came out of suspension. Using the displacement efficiency and shear rates obtained, a new dynamic completion damage test was devised to determine the potential for screen plugging. Finally, an overview will be presented of how Equinor's approach to completion damage has changed because of this study, with increased focus on achieving a better balance in the evaluation of formation and completion damage.