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Bentonite is not typically used as the primary fluid-loss agent in normal-density slurries. In low-density slurries, where higher concentrations can be used, it may provide sufficient fluid-loss control (400 to 700 cm 3 /30 min) for safe placement in noncritical well applications. Fluid-loss control, obtained through the use of bentonite, is achieved by the reduction of filter-cake permeability by pore-throat bridging. Microsilica imparts a degree of fluid-loss control to cement slurries because of its small particle size of less than 5 microns. The small particles reduce the pore-throat volume within the cement matrix through a tighter packing arrangement, resulting in a reduction of filter-cake permeability.
Abstract The primary objective of oilwell cementing is zonal isolation (i.e., restricting fluid movement across various zones within formations). Another equally important function is to support casing from various operationally induced mechanical and thermal stresses. To achieve successful zonal isolation, the cement sheath should possess important properties, including low permeability, high early compressive strength, good tensile strength, etc. This article presents a detailed experimental investigation of the effects of various nanomaterials on cement slurry properties. Nanomaterials are used in several fields, including catalysis, polymers, electronics, and biomedical applications. Because of their small particle size, these materials have high surface energy and hence higher reactivity. For this reason, nanomaterials are often necessary in small quantities for enhancing specific properties of the base material. The development of high-performance fluid systems for oil and gas applications is possible through nanotechnology. In recent years, many studies have shown the usefulness of nanomaterials in enhanced oil recovery (EOR) and drilling fluid applications. Investigations have also shown the use of nanomaterials in oilwell cementing. The experimental investigation of the effects of various nanomaterials on cement slurry properties shows that the addition of a mere 1.5% of halloysite increased tensile strength by approximately 141%. Similarly, the addition of nano-alumina resulted in achieving early compressive strength at temperatures as low as 40°F. Hence, these nanomaterials can act as nonchloride-based accelerators for low-temperature applications. Additionally, it was observed that, to obtain the greatest benefit of using nanomaterials, it is necessary to disperse them in desired media before use. The results of this study on the applications of nanotechnology in oilwell cementing provide an opportunity to use nanomaterials for enhanced cement slurry properties with minimal cost.
Abstract The two principal functions of oilwell cementing are to restrict fluid movement between zones within the formation and to bond and support the casing. Apart from these, the cement sheath also protects casing from corroding, protects the casing from shock loads when drilling deeper, and plugs lost circulation or thief zones. Once cement is placed in the wellbore, initial setting occurs wherein development of compressive strength becomes more important for further drilling operations. Early strength development is important to help ensure structural support to the casing and hydraulic and mechanical isolation of downhole intervals. Delays in strength development cause significant amounts of lost time because of the need to wait on cement (WOC). Typically, an accelerator is often used to enable early strength development in cement. It is desired that an accelerator should improve overall compressive strength without causing excessive gelation. Nanomaterials (being smaller in size and higher in surface area) are used in several fields, including catalysis, polymers, electronics, and biomedicals. Because of a higher surface area, these materials can also be used in oilwell cementing to accelerate the cement hydration process. Moreover, they are often required in small quantities. This paper documents a case in which nanosilica was used in cement formulations to develop high early strength. Nanosilica also helps enhance final compressive strength and helps control fluid loss. Using the correct quantity of nanosilica, it is possible to design cement slurry with low rheology and good mechanical properties while controlling fluid loss.
Abstract The frontier exploration drilling campaign in the Kingdom of Saudi Arabia for LUKOIL Saudi Arabia Energy Ltd started in January 2006. LUKSAR, a joint venture between Lukoil & Saudi Aramco, took pragmatic approach to project management. A careful analysis of campaign challenges with proper planning to meet the drilling campaign targets. One major challenge was to stick to well program to ensure well targets are met and exploration objectives achieved. The reduction of wellbore diameter due to hole problems during well construction has always posed a great challenge to well completion. Having said that, there are few technologies at present that provide the capability to execute well intervention/work-over in slim hole wells and where there are available, they usually cost a fortune. The restriction created in reduced hole sizes typically results in a complicated drill stem testing program (DST), formation fracture pressure limitation, decrease in production rate due to restriction in tubing selection and high intervention cost. On Luksar Expl well #4, the above mention challenge was a reality. While drilling, encountered severe loss circulation in Shu'aiba carbonate formation compounded with sloughing shale problems in the shallower Wasia formation. As a result, it became difficult to drill further and set planned casing at bottom. Utilizing expandable tubular across loss circulation zone enabled Luksar to restore the original well casing design. Introduction Losses of whole mud to subsurface formations is called lost circulation or lost returns. Historically it is one of the primary contributors to high mud cost. Other hole problems such as wellbore instability, stuck pipe and even blowouts have been the result of lost circulation. Besides the obvious benefits of maintaining circulation, preventing or curing mud losses is important to other drilling objectives such as obtaining good quality formation evaluation and achieving an effective cement bond on casing. The Shu'aiba Formation consists mainly of different types of carbonates (limestone and dolomite) depending on the well location. The vast extent of Shu'aiba is porous with fast ROP. Shu'aiaba is an oil and gas reservoir in some of the off-shore wells. In 90% of areas it is a loss of circulation zone like in all Gulf States and especially in the Kingdom of Saudi Arabia. Estimated pore pressure range 8.4–8.5 lbm/gal with recommended mud weight 8.7–9.9 lbm/gal. The majority of non-productive times associated with drilling through this reservoir include:Lost Circulation Unexpected high-pressure areas Hole integrity and wellbore stability Formation to formation cross flow Drilling through such formations provides many opportunities to experience one or more of these risks either while RIH, drilling or POOH. These risks potential means that at least one additional string may be needed to isolate the troublesome zone and to drill ahead to the planned casing point.
Abstract It is often desirable to be able to intervene to isolate specific areas within a wellbore. Throughout the life of a well, undesirable changes to production such as increased water may occur that cannot be easily dealt with using mechanical means, unless the completion has been designed with this in mind. Examples include flow through uncemented annuli, or from part of a gravel packed completion. In such cases, a possible solution may be to pump a treating fluid with properties that will provide the isolation required. Several different systems are available such as crosslinked polymer fluids, portland cement, or other hard setting materials. This paper reviews the properties of one such product, a magnesia cement system, evolved from chemistry that had previously been employed in other applications. The new technology uses fine-grained materials that can be squeezed though small restrictions such as narrow annuli, slots or perforations, or through well screens and into the gravel pack beyond, where later they will set hard and provide selective isolation of the treated section to prevent the flow of unwanted fluids. As with the original chemistry, the new system is composed of acid soluble components, allowing the solid set material to be removed in the future should it be required. This paper will identify the requirements associated with selecting hard setting materials use in for zonal isolation. It will discuss the development of this squeezable magnesia cement system, showing how it meets these requirements. The results of extensive laboratory evaluations will be reviewed and recent case histories will be discussed. This technology is expected to find wide application in many existing gravel-packed and un-cemented wells worldwide, when low risk long-term zonal isolation becomes required. Introduction Many problems may present themselves when unwanted water or gas approaches a producing wellbore. The most apparent may be a reduction in the well productivity, which can be caused by the onset of multi-phase flow and relative permeability effects, by the creation of water blocks, by an increase in produced water cut and corresponding increased hydrostatic head, or by an unfavourable water flooding sweep efficiency due to high permeability streaks. Additionally, an increase in water production can also lead to higher corrosion of wellbore tubulars and surface equipment, and additional productivity losses from inorganic scaling and fines migration. On surface, the water-handling facilities have to be built to cope with the large volumes involved, and of course, the produced water has to be disposed of by an acceptable means. All of these issues have an associated cost, which ultimately must be offset against the value of the produced hydrocarbon, effectively lowering the net value of the produced oil or gas. These costs do not appear to be well recognised, although they can be substantial, particularly in mature areas where the water cut is high. While there are several well-proven chemical treatment solutions available for reducing water or gas flow within the reservoir, for the most part, it is essential that these treatments are applied directly to the water/gas zone which is presenting the problem. If erroneously squeezed into the wrong zone, a shut-off treatment will stop hydrocarbon flow as efficiently as it stops water/gas flow. Often it is not possible to squeeze the water zone in question because the type of completion will not allow that zone to be isolated. These cases include wells completed with slotted liners, sand control screens, gravel packed intervals and multi-lateral sections. This is also the case when the water flow is occurring in an uncemented annular space or between casing strings. Mechanical zonal isolation is not possible in these completion types because a flow path exists beyond the inner casing or screen. This paper discusses the development of a removable zonal-isolation product which can be used to overcome the above limitation.
Abstract Value may be created by applying innovative technology in challenging zonal isolation applications. Risk evaluation in deepwater cementing can be accomplished without jeopardizing environmental impact and cost effectiveness. Some of the highest risks encountered in deepwater cementing operations are related to low temperatures and the existence of shallow water flows (SWF). Generally, for cementing low-temperature zones, high early strength blends with set accelerators are utilized. At normal temperatures, Class A or Class H Portland cements are normally preferred in Gulf of Mexico (GOM) operations. The cement system for SWF zones should have a relatively low density and a short transition time to help maintain well control. Presented in this paper are examples of how a single cement system has been used to meet all design criteria for delivery of deepwater well cementing. A disadvantage in using a variety of cement types and blends for cementing in an offshore environment is that the unused preblended materials designed for a given depth are often discarded, and new blends are made up for the subsequent cementing operations. This can result in increased material costs and repeated trips to shore. It is desirable, both economically and environmentally, for an operator to be able to use the same neat cement for cementing wells at multiple depths. This paper presents details of an innovation that involves cementing offshore wells with SWF problems with only one neat cement by using versatile additive technology. Case histories for cementing several wells in the GOM in water depths greater than 2,000 ft are presented. In all cases, flowable salt-water zones were encountered while drilling. The operator's risk assessment of the problem was uncertain at the time of well design and planning because of the exploratory nature of the wells drilled. The liquid additive system for flow control gave the operator the flexibility of having the additives on the rig at the time the holes were drilled. The operator could evaluate the flow potential before deciding to use the system or use other options. The foamed cement system used in these case studies used a liquid additive for SWF control. The remaining portions of the wells were cemented with the same neat cement by using different liquid additives. This in turn helped reduce environmental impact of wasted cement and saved the operator considerable capital for the wells drilled. Introduction Cementing of oil wells in deep water (greater than 1,000 ft) presents special challenges to slurry design. The temperatures are near 40°F at the mud line, and near 200°F at the bottom of the well. Cement slurries for low-temperature applications need to be activated with set accelerators, whereas slurries for high temperatures need to be retarded to allow for safe placement time and minimum waiting-on-cement (WOC) time. The compressive strengths at the end of WOC time should be adequate enough to support the casing. The rate of compressive-strength development is slow for typical single-cement-based slurries at temperatures such as those at the mud line. The slurry design requires special blends that are capable of developing early strengths. In the GOM area, the zones where the conductor casing is cemented are often unconsolidated and are geologically relatively young (Fig. 1). Consequently, these shallow formations have the potential for abnormally pressured saltwater sands, also known as SWF zones. Weak formations and pressured sands present very narrow margins between the pore pressure and fracture gradient, which can cause a loss of cement returns.
While there have been several good papers that describe the dissolution of Portland cement by hydrochloric:hydrofluoric acid (HCl:HF) solutions, no one has established a detailed comparative test procedure. The absence of a single, specific methodology left all parties to form their own interpretations of the acid solubility test described briefly in SPE 18986.
Discrepancies between the various procedures produced inconsistent results. Some laboratories were keeping the heated acid in glass vessels for extended periods before the cement specimen was introduced. Using glass vessels allows the HF to spend on the glass instead of the cement. Others were using grease on the curing molds and testing the cubes without adequate grease removal; this limits cement/acid contact. Different methods for agitating the acid and suspending the cement cubes in the acid were also being employed. One company was desiccating the specimens before acid immersion; another was using a complete inhibitor and surfactant package. Even the concentration and volume of acid was not universally agreed upon. All these factors must be controlled for an accurate comparison of data between different laboratories.
Representatives from two operating companies have developed a jointly endorsed and very explicit methodology for conducting cement acid solubility tests. Equipment, chemicals, preparation methods and report forms were specified in extreme detail. This procedure was designed to address the above mentioned problems and yet be cost effective and applicable in any field lab.
Although the new test remains qualitative, it has provided consistent comparisons of conventional and microfine Portland cements. A quantitative method would require more costly, specialized equipment and limit field application.
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.
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.
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.
In various formulations, microsilica cement slurries are finding increasing utility in oilfield cementing applications. In the course of these applications, many microsilica slurries are being used in environments which subject the set cement to bottom hole static temperatures in excess of 230deg.F.
While 35% fine silica by weight of cement (BWOC) has been extensively researched and accepted as a high temperature cement stabilizer, very little if any research has been published on the effectiveness of published on the effectiveness of microsilica in this application. The results of this study reveal that microsilica displays promise as a viable alternative stabilizing material, with the added benefit of medium to low slurry density.
Microsilica, also known as silica fume or ferrosilicon dust, is a by-product of the industrial manufacture of ferrosilicon and/or metallic silicon in high temperature electric arc furnaces. The material typically contains 93-96% SiO with trace amounts of other elements. Completely amorphous, the material consists of spherical particles as small as 0.1 microns (See Table 1). As a concrete admixture, the material has found widespread acceptance in the construction industry, and is being integrated into many oilfield cements as well. Due to certain inherent characteristics, the use of microsilica in oilfield cement slurries will usually dictate higher mix water ratios than would be utilized in non-microsilica slurries. The higher water ratios result in lower slurry densities. Since many of the oil and gas wells drilled today are into low pressure or depleted reservoirs, there is an increasing demand for mid to low density filler and/or completion cements.