Abstract Placing the cement slurry in the entire annulus, in both the wide and narrow sides, is essential to achieving effective zonal isolation. Well conditions, such as deviated wellbore geometry, eccentric annulus, and gelled drilling fluid, pose unique challenge in achieving this objective. It is known in the industry that pipe movement helps improve hole cleaning and cement-slurry placement. However, the quantitative effect of pipe rotation on hole cleaning and cement-slurry placement for a given eccentricity, flow rate, and geometry was not well studied. Hence, it was difficult to design a primary cement job where the effects of all these parameters were considered at the same time and optimized for best results. The effective velocity and pressure drop in an eccentric annulus with and without pipe rotation is modeled for Herschel-Bulkley fluid. This is then extended to evaluate the effect of pipe rotation on hole cleaning and cement-slurry placement. The modeling clearly demonstrates the improvement in hole cleaning from pipe rotation in an eccentric annulus. Now there is a tool available to study the interaction of various factors on hole cleaning and optimize them for the well in question. The results from the modeling study have been compared with field data. The comparisons show a good match between the improvement in cement-slurry placement predicted that was inferred from the cement bond logs. The study clearly indicated the importance of using representative rheological model and input values. The modeling results and field validation are presented and discussed. The work presented in this paper should help the industry optimize the various factors during a cement job to help maximize hole cleaning and cement-slurry placement in the wide and narrow sections of the annulus. This should help in achieving zonal isolation for the life of the well and reduce operating expenses by reducing remedial jobs. Introduction In recent years, the study of the hydraulics effects of drillpipe rotation on annular pressure drop and equivalent circulating density (ECD) has been receiving a great deal of attention. Initially, researchers focused on theoretical studies and laboratory measurements of pressure drop (?P) (Luo and Peden 1987; Walker and Al-Rawi 1970). In these studies, the authors observed that, under laminar-flow conditions, drillstring rotation served to lower pressure drop and ECD. Several studies were later conducted in support of slimhole drilling efforts where the Di/Do ratios are quite high (0.75 to 0.85). In one of the slimhole drilling studies (Bode et al. 1991), data showed increased ?P with increasing drillpipe rotation speed (up to 200 rev/min) for fluids with Reynolds numbers < 2000. In the second slimhole study (Delwiche et al. 1992), field measurements of drillpipe-rotation effects on pressure drop were made, and the results showed increasing pressure drop with drillpipe rotation speed. In a third slimhole drilling study (McCann et al. 1995), the authors concluded ?P decreased with increasing drillpipe rotation speed for power-law fluids in laminar flow. In all of these early studies, no attempt was made to model the results into a coherent calculation scheme. In Marken et al. (1996), the authors reported increasing measurements of ?P with increasing drillpipe rotation speed (18 to 67% increase over the ?P reported at 0 rev/min). They cited the occurrence of centrifugal instabilities (Taylor vortices) and uncertainties in annular eccentricity and drillstring motion and vibration as reasons for industry models to incorrectly predict annular pressure drops with drillstring rotation. Later, others studied the effects of drillstring rotation in fluids in laminar flow from a theoretical perspective and concluded rotation had a significant effect on pressure drop, especially in smaller-diameter gaps through which fluid was moving (Ooms and Kampman-Reinhartz 2000). However, the modeling in this work was valid for Newtonian fluids only.

Abstract Solution for a Long-Standing Cementing Challenge—Intelligent Cement Set Control Additive Industry has always found it challenging to cement long zones with a single slurry system. A huge temperature differential exists between the bottom and the top of a long cement column. Cement slurry designed for the circulating temperature at the bottom of the long column will sometimes fail to set at the low temperatures at the top of the cement column. These results in rig nonproductive time and in certain cases can lead to well integrity problems. While setting unplanned kickoff plugs or plugging and abandoning wells, the bottom hole temperature may not be very well known. The slurry setting is sensitive to temperature, and the setting time can change substantially if the actual bottom hole temperature is different from that used for design. This leads to failure of the cement plugs. This issue is more pronounced around 200°F. A new generation of engineered cement set control (ECSC) additive has been developed to successfully cement wells in the scenarios mentioned above. The additive works intelligently and not only provides sufficient placement time for bottom of long cement columns where temperature is higher, but at the same time allows for fast compressive strength development even at the top, where temperatures are lower. A single slurry design incorporating the additive has been used successfully in setting multiple plugs at different depths, with varying bottom hole circulating temperatures, demonstrating the relative insensitivity of the retarder to temperature variation. This paper discusses successful use of the additive in the field for setting multiple plugs at varying depths and temperatures using the same slurry design. Field cases with results related to the various applications will be provided. Introduction Thickening time of cement slurry plays a vital role in cementing operations. The type of cement, density, fluid loss control, compressive strength and free water are important characteristics as well. However control of cement setting time is essential for successful cementing operations. Several problems can result from ineffective setting time control. Total operating cost associated with waiting on cement (WOC) is also a critical factor. The time needed to achieve enough compressive strength in order to resume drilling is determined by the cement formulation and the well conditions. A reduction in the WOC time can potentially yield considerable savings to the operator particularly with the high rig daily rates in today's offshore environment. ECSC additive is almost temperature independent within its temperature range and has a very well defined linear behavior that makes it predictable and safe to use even when small variations in temperature are present. This characteristic allows cement to set more uniformly where temperature geothermal variations are more evident and also when long columns of casing are being cemented. ECSC linear dependency on temperature will prevent longer setting times of cement slurry that may allow oil/gas or water influx in the slurry and compromise good casing isolation. Reduced WOC has being achieved especially in cases where temperature at the TOC is much lower than BHCT. QHSE (Quality Health Safety and Environmental) Compliance Today international environmental statutes and guidelines are the strongest driving force to restrict industrial use and discharge of environmentally harmful chemicals. The development of more environmentally acceptable products requires a thorough screening of environmental fitness and status of compliance with relevant laws and regulations. This fact dictates the initiation of several initiatives for environmental improvement addressing human health as well. Results verify that environmentally improved products can be efficient, as well as cost effective.

Abstract The cementation of any casing string is an integral part of well construction. The main objective of primary cementing is to provide complete and permanent annular isolation from mechanical and chemical stresses during drilling and production stages of the life of the well. Through tubing rotary drilling (TTRD) technology presents its own challenges to cementing design. The management of the equivalent circulating density (ECD), typically at its highest levels during the final stages of the cement slurry displacement, is a critical parameter of the fluids design process. The use of bi-centre drilling bit design, which achieves a larger open hole size than the pass-through diameter, introduces centralization difficulties and add complexity to the removal of the drilling mud prior to cementing. The accepted cementation approach for TTRD wells is to formulate low rheological fluids such that, maximum advantage can be taken from the annular velocities for mud removal efficiency. By challenging the common design practices a design was proposed that combined low and high rheology fluid properties to achieve the objectives set out for the cementing operation of the 2 7/8 inch liner. Introduction Achieving complete and permanent annular isolation by the cement slurry is a challenge that is not particular to TTRD. The parameters that affect the quality of the cement bond with both the formation and the casing surfaces are well documented and can, in most cases be addressed by taking into account the specific objective for each operation. Whilst 100% bond index across non-reservoir / non-critical zones cannot be justified, the target reservoir zones required pressure competent isolation. The TTRD liner cementation for the J25 well was critical to the success of the project as failure to isolated the complex pressured multi-zone reservoir would create well production difficulties that would compromise the viability of the project. From the hydrodynamic discipline the success of a cementing operation is entirely dependant on completely removing the drilling mud from the section of the annulus elected for isolation. To this effect, a spacer fluid is pumped ahead of the cement slurry, to displace the drilling mud using one of two criteria: Displacement by the effects of the kinetic energy transferred to the fluid from the pumping rate Displacement by the inherited design properties such as density, friction pressures and minimum pressure gradient (MPG) of the fluid. In reality, due to the parameters set by the multi-discipline design requirements involved at the well construction stage, the centricity of the pipe in relation to the open hole is unlikely to be optimum over the entire length of the selected annulus. The fluid dynamics model, for a given cross section of the well, will be characterized by the velocity differential between the wide and the narrow annulus. The successful removal of the drilling mud depend largely on the level of understanding of this velocity profile and engineering practices used to develop the adequate fluid placement sequence.

Abstract For many years, oil based muds have shown proof of efficiency towards hostile drilling cases especially water sensitive shales or high temperature wells. However, their use is subjected to more and more constraints due to the fast evolution of environmental legislations. One of the possibilities to avoid this problem while keeping the advantages of oil muds consists in substituting mineral oils by biodegradable vegetable oils such as fatty acid esters. The esters used in these new oil-based muds have an aerobic biodegradability of more than 85 % after 4 weeks and an anaerobic biodegradability of more than 60 % after 2 months. An original formulation has been developed, presenting very good properties up to 140C. Its performances are based on a properly choice of ester quality, emulsifying system and additives types, and on a severe control of lime concentration to avoid any risks of ester hydrolysis in conjunction to pH and temperature. Its behavior has been studied under bottomhole conditions, using an home made HT/HP flow loop, during aging. Contamination tests demonstrated the ability of ester-based muds to resist to possible contaminations i.e., sea water, drilled solids, cements during the drilling process. Introduction Oil-based muds are among the best performant and cost effective fluids in hostile conditions. They are used in particular when drilling water-sensitive shale, or when are encountered high temperatures, risk of important differential pressure sticking, exposure to acid gas, or long directionnal intervals requiring minimum torque and drag on the drill string. Even though they may be two or three times more expensive than water based muds, their use is justified by better performances and savings on mud maintenance. However their intensive use make mineral oil based muds an important source of pollution. During the last decade, environmental regulations have severely restricted the use of mineral oil based muds, mainly because of their impact in marine environment during offshore operations (1-6). All these general environment concerns have led to an extensive industrial research aiming at designing non toxic substitution fluids that could replace mineral oil based muds but have the same performances in a wide range of drilling conditions. Low toxicity mineral oils containing substantially lower concentrations of aromatic or naphtenics were used to replace diesel as the base fluid in these muds. However, the legislation has become more and more restrictive and even these classical low toxic fluids like kerosene have been contested and will progressively leave the market under the pressure of environmental requirements. P. 507^

Abstract Examination of Class G cement slurry retardation up to 250 degrees F has indicated that commonly employed retarders usually give a threshold of unexpectedly long thickening times at ~160–190 degrees F BHCT. Normally, thickening time is not linearly but exponentially dependent upon retarder concentration. The causes of the threshold of long thickening times have been investigated by carrying out appropriate hydration experiments on Class G cements at water/cement ratio 0.44 subjected to thickening under different API Schedule conditions. The cause of the threshold effect has been found to be surge in hydraulic reactivity of the ferrite (C4AF) phase from the Class G cement. The hydration products thus formed, mostly AFt phase or ettringite C3(A,F).3CaSO4.31-32H2O, are deposited on the hydrating clinker surfaces and in particular impede the hydration of the main cementitious particular impede the hydration of the main cementitious alite (C3S) to calcium silicate hydrate (C-S-H), the initiation of which is the prime cause of cement thickening. As a result thickening time is extended and not diminished. However, as the temperature rises above ca 190 degrees F, the increased hydraulic potential of the cement manifests itself. There is no longer an increased surge in ferrite phase hydration to obstruct C-S-H formation, so the C3S hydration rate rises again, culminating in lower thickening times once more. The threshold effect has important implications in cement slurry design. Introduction Cement slurries are designed in the laboratory using carefully controlled API and related procedures. From the viewpoint of cement slurry performance the key class of additives is retarders, because they are present to varying degrees in most cement slurries. Thickening time is a key factor in cement slurry design, because of its use in indicating the time available for pumping the slurry into position in the annulus before thickening and hardening take place. Thickening time has already been shown to be highly dependent upon cement and retarder types under given well conditions. In order to understand more fully the nature of thickening under retarded conditions, it was decided to investigate different common retarders under a variety of downhole conditions based mostly upon API temperature and pressure schedules with four different Class G cements. Liquid retarding additives were used here because of their greater overall utilisation worldwide. EXPERIMENTAL PART Four different API Class G cement (Cements 1–4) and four commonly employed retarders (A-D) were used in these investigations. Three of the retarders (A-C) were lignosulphonates and one (Retarder D) was a gluconate. P. 379

Abstract Gas leakage through cement in the annular space around a cemented casing is still a serious problem although new additives and improved techniques have reduced the problem. A new approach is the construction problem. A new approach is the construction of an emulsion cement, consisting of a double emulsion; water-in-oil-in-cement. Waterdroplets containing a controlled number of species are emulsified into mineral oil. This W/O emulsion is then emulsified into the cement slurry in small amounts (3–15 vol %). The effect of the emulsion on the cement slurry has been recorded through standard API tests. In addition the bond between cement and steel surfaces and the tightness against gas migration have been checked. Compared to other cement slurries, the emulsion cement shows promising results with respect to becoming a friction reducer and an anti gas migration additive. Further tests are necessary to determine the applicability of emulsion cement. Cement slurries behave different at high temperatures, and test procedures and test equipment must be improved in order to comply with down hole conditions. STATEMENT OF THE PROBLEM In sedimentary formations containing gas, known cementing techniques will frequently create problems like gas entering the annular space after the cement slurry has been pumped in place. Gas can flow through minor channels or pores in the cementing slurry from a high pressure zone into a lower pressure zone. Sometimes the gas can penetrate to the surface, or it can be penetrate to the surface, or it can be stopped at the well head. This type of gas migration can be dangerous and give blowouts and accidents. Even if the leakage is discovered before this happens, expensive repairs may become necessary. The causes of gas migration are caused by – free water- loss- poor bonding to the surroundings – loss of hydrostatic pressure Free water that is emitted during the hardening and settling process can develop water pockets in the hardened body. These water pockets can evolve into communication channels for gas when the water is suppressed. Chemical processes, temperature variations, and filtrate loss can cause creeping of the cementing slurry during the solidifying and hardening period. Mechanical stress during the following drilling and perforating operations may create cracks in the cement. Difficulties in obtaining good contact between the cementing slurry and the environment, and in suppressing the drilling mud may cause channels and gas migration. Before the solidifying process starts, the cement behaves like a liquid transferring hydrostatic pressure depending on density and depth. Early in the process, the cement stops behaving like a liquid, but rather as a plastic slurry with weak bonds and with free water in the voids. A volume reduction of the free water in the void structure will then cause a pressure reduction. Even with additional substances in the cementing slurry, which reduces the filtrate, water loss cannot be totally prevented. P. 397

Abstract A campaign in the North Sea was carried out to permanently abandon 24 wells using coiled tubing (CT). permanently abandon 24 wells using coiled tubing (CT). This was used to fulfil the Department of Energy requirement that the production screens had to be plugged back with cement prior to the removal of any plugged back with cement prior to the removal of any well completions. A review of the advantages of using CT and the operational difficulties experienced during the placement of the cement are presented. A financial comparison with present day abandonments, using a rig for the entire operation, is also presented. Introduction The recent surge of interest in cementing through CT in the North Sea is based on the results achieved in Alaska. In 1983, ARCO, Alaska pioneered the use of CT for cement squeezing during workover operations in the Prudoe Bay field. A few years later BP Exploration Prudoe Bay field. A few years later BP Exploration followed suit. The principle motivation for using CT for cement squeezing is economic: to reduce workover costs in an environment where rig mobilization and operational costs are becoming prohibitive. Significant advantages have been identified by using CT for remedial cement squeeze operations: * Since well pressure control can be maintained at the surface through a stripper and a blow-out preventor (BOP) assembly, it is possible to run intolive wellbores. * Existing production tubing and wellheads do not have to be removed to access the production interval. * Possible slurry contamination during the placement is minimized. * Since the CT can be reciprocated while pumping, exact spotting of a small volume of cement slurry at the zone of interest is possible. It was this economic interest that led Elf Aquitaine, Norway to consider CT for part of their CDP-1 Platform abandonment project. FRIGG GAS FIELD Frigg is a "dry gas" field located on the Norwegian-UK border. It was discovered in 1971 and put on stream in 1977 from two 24 slot production platforms. The initial gas in place is estimated to have been 235 BSm3, with final recovery estimated to be in the order of 177–180 BSm3. The average monthly flowrate has been as high as 70 MMSm3 /day due to pre-sale and banking arrangements with the fields connected to the Frigg transportation system. The reservoir consists of friable sands of Lower Eocene and Paleocene age with very good poro/perm characteristics. The initial gas column was up to 525 feet (160m) thick and overlying a thin oil rim. P. 117

Abstract Coiled tubing cement squeezing has proved to be a successful water shut-off method in the Forties Field. Six cement squeezes have been carried out to date on three different platforms in the field. The jobs have been carried out either as a stand-alone well service remedial operation or as a prelude to a full rig workover. Production increases have averaged 4.5 mbopd (720 m3/d) per well with the most successful operation resulting in a post-squeeze rate of 17 mbopd (2700 m3/d) at 10% water cut compared to a pre-squeeze rate of 6.9 mbopd (1100 m3/d) at 55% water. This paper describes the well histories, the production profiles and the decision process in selecting coiled tubing cement squeezing over more traditional methods of isolation. It discusses the preparatory work required for proper slurry formulation, the equipment lay-out and step by step procedures used in performing the job. The paper reviews the difficulty in sizing the slurry volume given the friable nature of the reservoir sandstone. It also highlights the differences and difficulties in performing the operation offshore compared to a similar land based operation. Introduction The Forties Field was discovered in October 1970. It was the first major oil discovery in the U.K. sector of the North Sea (Figure 1) and with 4.3 billion barrels (683 MMm3) OOIP, remains the largest find to date. The main field reservoir is a Palaocene sandstone in a four way dip closed anticline which initially contained 614 feet (187m) of oil column with the original OWC at 7273 ft (2217m) vertical depth subsea (Table 1). Current reservoir pressure and temperature at datum (7135 fttvdss, 2175m) are 2900 psig (20 MPa) and 208 deg F (98 deg C). The recovery mechanism is bottom aquifer drive supported by peripheral seawater injection. The main field is developed from four platforms, Alpha, Bravo, Charlie and Delta (Figure 2). They have the same basic design and are all capable of separation, NGL recovery, treating produced water for disposal and injecting seawater for reservoir pressure maintenance. Production from the main field commenced in September 1975. In March 1987 production started from a fifth, minimum facility platform, Forties Echo, located to the south east of the main field. To date, 85% of the 2.48 billion barrels (395 MMm3) reserves has been produced and the challenges ahead are to stem production declines and manage increasing water production at the lowest possible operating cost. With the advent of seawater breakthrough into producing wells, traditional methods of water isolation were found to be increasingly ineffective. This paper discusses the recent introduction of coiled tubing cement squeezes to shut-off water in the Forties Field. P. 393^

Permission to copy is restricted to an abstract of not more than 300 words. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper was presented. Publication elsewhere is usually granted upon request provided proper credit is made. Abstract The requirements for zonal isolation in Conoco's Hutton field have greatly increased as production from the field continues. High differential pressures approaching 1500 psi between zones which are less than 15' apart have made obtaining effective isolation of paramount importance. Problems with zonal communication behind the Problems with zonal communication behind the production casing were experienced due to an production casing were experienced due to an incomplete cement sheath. High pressure water zones flowed through cement channels to a low pressured oil zone and reduced oil production. In addition, water injection production. In addition, water injection did not enter the desired zone. A review of the methods used for primary cementing was completed and recommendations were made to improve the quality of the cement job. These recommendations were then implemented on subsequent wells. These recommendations included practices for conditioning the hole for the casing, designing the cement slurry and spacer system, and running and cementing the casing. A high priority was placed on preparation of the hole for casing. Drilling practices were addressed such as maximum preferred hole angle, circulation rates, properties of the drilling fluid and making a conditioning trip after logging. The cement slurry design was addressed in concert with the mud and spacer systems. A new test was devised to design a spacer system suitable for water wetting and mud filter cake removal. Rheological, settling and thickening properties of the slurry were addressed. Casing running and cementing practices were reviewed. Sandblasting the casing, casing centralization, casing running speeds and slurry volumes were engineered. Fluid properties and circulation rates were properties and circulation rates were optimized prior to cementing, as well as the use of multiple wiper plugs for separation of the mud, spacers and cement. Selection of cement mixing equipment and onsite supervision were also addressed. As a result of this work, substantial improvements in primary cementing have resulted in near perfect cement bonds and elimination of zonal communication in the Hutton field. Introduction The Hutton Field was discovered in 1973 in the UK sector of the North Sea (Figure I). The field was developed using the world's first commercially operated tension leg platform (TLP). Initially 10 wells were platform (TLP). Initially 10 wells were predrilled through a 32 slot template. predrilled through a 32 slot template. Since installing the TLP, 18 wells have been drilled and several side tracks have been completed. The Hutton field geological structure consists of three fault blocks, a structure map is shown in Figure 2. The reservoir contains four sand members. A typical cross section of the reservoir is shown in Figure 3. The sand members vary in thickness from 35' to 65' (10.7 to 19.8 m). Due to the nature of the faulting, sand deposition and field development, recently drilled wells have encountered high differential pressures between oil and water bearing zones which are relatively close together. A pressure differential of 400 - 800 psi (2758 – 5516 KPa) between the Massive Sand and Basal/Mica/Middle Shaly Sands are a common occurrence in the field. Figure 4 shows the formation pressure data from a recently drilled well. On another well, a 1500 psi (10,342 KPa) differential pressure was evident between 2 zones which were less than 15' (4.6 m) apart. Obtaining zonal isolation between these sand members is the most important part of drilling in the Hutton field. Problems have been encountered on wells Problems have been encountered on wells where an incomplete cement sheath has allowed a high pressure water zone to flow behind pipe and reduce oil production from a low pressure oil zone. A successful primary cement job is essential to ensure that when the well is perforated only the fluids from the intended zone are produced. A similar requirement exists for an injection well, where only the target zones should receive fluid.