Proposal This paper presents the results of a study of processes and technologies for the thermal desorption of oil from oil-based drilling fluids cuttings for both onshore and offshore applications. A field investigation of available technologies designed to separate oil from oil-based drilling fluids cuttings by thermal desorption was conducted. In addition, some technologies that perform separation by physical-chemical means were also investigated; however, all commercial processes presently available use thermal desorption. The mechanisms of desorption of oil from cuttings were investigated. Process parameters and theoretical concepts for thermal desorption by distillation were developed using proprietary computer simulation programs for the distillation of hydrocarbons. Theoretically ideal temperatures for the process were calculated for various conditions and for various oils. The impact of moisture and oil content on the heat balance was calculated. The recoverability of the oil under various conditions was investigated. Nineteen companies were contacted for information on their desorption technology. Twelve company sites were visited to determine the developmental stage of their technology and to determine how well the technology functioned in the field. The technologies were evaluated for air emissions, liquid emissions, safety, oil content of processed material, space requirements, utility and chemical requirements, and other operating and design factors. Applicability of the technologies for offshore use was evaluated. Safety and environmental issues for each technology and the recycling of oil are also addressed in this paper, along with future work needs in this area. Introduction The need for thermal desorption of oil from drilling cuttings for environmentally acceptable disposal of the cuttings was identified in the early 1990s. Technologies used for this purpose evolved significantly in the intervening years. The requirements for the level of oil removal have also evolved. The numbers of base fluids used in the drilling fluids have increased beyond diesel and mineral oils to a wide range of synthetic fluids that include, but are not limited to, alkanes, olefins, esters, and blends thereof. For the purposes of this paper, the term "oil" covers all such base fluids used in continuous phase of invert emulsion drilling fluids. The requirements of desorption technology differ significantly depending on three main factors:where the operations take place,the Total Petroleum Hydrocarbons (TPH) levels permitted to remain on the cuttings, andthe protocols for TPH measurement. The authors investigated 16 different desorption technologies in various stages of development from bench-scale units to pilot-plant stage to commercially available units. The focus was primarily on thermal units because these were the only types commercially available at this time. In Europe and South America, the processed cuttings typically measure less than 1% by weight of TPH before disposal in landfills. For offshore disposal of cuttings in the UK sector of the North Sea, an oil content of less than 1% is also required, and any discharged water must have less than 40 parts per million (ppm) of oil. Generally, oil-based cuttings generated offshore in the North Sea have been taken to land for treatment and disposal because, until recently, no method for reducing the oil content to less than 1% was available at an offshore location. Regulatory agencies in other areas have also set standards for the levels of TPH in cuttings whether disposed of offshore or on land. Some processes do not require thermal desorption technologies. For example, in the Gulf of Mexico the discharge of cuttings with TPH levels of either 6.9% or 9.4% by weight, depending on the synthetic oil selected, is allowed if other toxicity and biodegradation standards are met or exceeded. These levels of oil on cuttings can be reached with mechanical systems. However, the trend in environmental regulations is toward greater stringency. An increased demand for minimal TPH levels in treated cuttings will drive the development of more effective oil-removal technologies.

It has long been accepted that non-aqueous invert emulsion drilling fluids provide improved drilling performance compared to traditional water-based systems. Use of diesel, mineral oil, and more recently, synthetic materials such as olefins and paraffins as base fluids has gained global acceptance. However, the disposal of these materials and associated drill cuttings can generate environmental concerns. The capability to remove oil or synthetic oil from the cuttings before disposal can significantly reduce the long-term environmental effects of disposal. In addition, effective recovery of costly synthetic fluids could improve the overall economics of drilling. This paper summarizes research efforts into development of a technique that uses liquefied hydrocarbon gases as solvents to extract oil from cuttings. The laboratory data presented shows that a wide variety of fluids can be efficiently recovered from cuttings. Residual oil on cuttings levels can be reduced to concentrations exceeding the standards typically required for disposal or discharge, with no thermal energy requirements and recycling of the solvent phase and recovered fluid. Risk assessments indicate that the technique can be safely applied at both onshore and offshore operations. Introduction Invert emulsion drilling fluids, also known as nonaqueous fluids (NAF) or oil-based muds (OBM), were introduced in the 1960s. These fluids are usually preferred over aqueous (water-based) drilling fluids because they improve drilling performance, particularly with regard to drilling rate, hole stability, thermal stability, and lubricity. Recent advances in water-based fluids1 have gone a long way to close this performance gap, but in many cases, invert emulsion fluids are still the preferred option. Invert emulsion drilling operations generate drilled cuttings mixed with invert emulsion fluids. Typically, drilled cuttings contain 5–15% (by weight) of the base fluid used to build the invert emulsion fluid. Typical wells generate 1000–2000 metric tonnes (MT) of cuttings per well. Therefore, a typical well may dispose of as much as 300 MT of base fluid. The disposal of drilled cuttings associated with invert emulsion fluid can represent a potential environmental concern, especially in offshore operations where drilled cuttings have been traditionally disposed of in the sea. Other factors, including the tightening of environmental regulations, shipment of cuttings to shore, and generation of invert emulsion fluid cuttings in land operations can also add to environmental concerns regarding the disposal of cuttings on land. Because of these concerns regarding the environmental impact of disposal of invert emulsion fluids cuttings, a number of technologies have been developed that subsequently led to the technology described in this paper. Evolution of Invert Emulsion Fluids The first invert emulsion fluids were created with diesel oils, primarily because of the low cost and widespread availability of diesel. In many parts of the world, diesel fluids are still successfully used. However, in the early 1980s, many operators became concerned about the occupational health risks associated with diesel-based fluids and consequently requested fluids based on oils with a lower aromatic content and flash point. As a result, mineral oils became a common invert emulsion base fluid, even though a higher degree of refining made them more expensive than diesel. In many areas, operators have changed to mineral oils, especially for land-based and zero-discharge offshore activities.

Introduction Since the introduction of various environmental regulations limiting or banning the discharge of various types of drilling fluids and associated drill cuttings globally, there has been considerable growth in what has become known as "zero discharge" or "ship to shore" operations. In these operations drill cuttings and associated waste fluids are collected on the rig in cuttings boxes (also known as skips) and then sent back to shore for disposal or treatment prior to disposal. In other situations, depending on local legislation, drill cuttings are collected and then transported to a grinding and slurrification package prior to injection downhole.[1,2] In addition, even where the discharge of cuttings offshore is still permitted, there is often now a requirement to collect and transport drill cuttings on the rig for secondary treatment such as cuttings dryers that reduce the amount of drilling fluid associated with cuttings prior to discharge.[3] These types of operations typically create operating challenges and additional costs associated with the required additional equipment, manpower, rig space, and in some cases, can even require significant rig modifications. Various technologies have been used to date for the collection and transportation of drill cuttings. These includescrew conveyors, vacuum systems, positive displacement pumps and pneumatic systems.4 The benefits and limitations of all of these systems are discussed in this paper with emphasis on the testing and performance of a positivedisplacement drill cuttings transfer system previously developed by Halliburton. Depending on the technology used, there are safety and environmental risks associated with "ship to shore" operations and the use of cuttings boxes, such as significantly increased crane operations, housekeeping and deck space issues, transfer of wastes to boats or barges, the use of screw conveyors or high pressure pumping equipment and increases in waste volumes generated and eventually disposed of. In this paper a new system for handling drill cuttings in zero discharge and other drilling waste management operations is described. This system has been shown to handle all types of drill cuttings from dry cuttings to slurries and even whole drilling fluids and has features that overcome many of the limitations of other systems currently used in the industry to transfer cuttings. Field experience and case histories show that this system is capable of collecting and transferring drill cuttings over the distances typically required on drilling rigs (and further if necessary) and at the rates required to keep up with drilling operations without many of safety concerns and limitations of other systems, without increasing volumes of waste generated and with minimal footprint and rig modifications required. Properties of Drill Cuttings Perhaps the most significant challenge to developing technology to transfer drill cuttings is that drill cuttings are very inconsistent by nature, ranging from high liquid content slurries to almost dry depending on drilling rates and conditions, drilling fluids used and solids control equipment efficiency. The drilling rig's solids control equipment is designed to separate the drilled formation from the drilling fluid based on either the size or density of the solid particles. The drilling fluid can then be re-used. However 100% separation is not possible with current technology. Instead drill cuttings are generated with a significant fraction consisting of drilled formation and other solids such as commercial clays and weight materials, and a fraction of drilling fluid associated with those solids. The relative percentage of each will vary greatly. Depending on the relative fraction of solid to liquid and solid particle size, drill cuttings can behave as either a liquid (high liquid content), a paste (intermediate liquid content) or as a solid material such as sand or gravel (low level liquid content). A range of the physical properties of drill cuttings is proposed in Table 1, but this is only to be taken as a guide.

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To meet the challenges to the industry of increasing hydrocarbon demand, increasing well complexity, reduced employee experience levels and the large physical distances between operational centers, advances in digital technologies are being increasingly leveraged by both operator initiatives and service company initiatives such as Halliburton's Digital Asset. Terms such as "smart wells" and "real time" have become more commonplace. Data is being generated faster than ever. The ability to interpret this data, model the data and implement optimized solutions in real time is critical to operational success. The demands placed on operating in a cost efficient manner, with greater returns on investment are ever present.The use of a Knowledge Management collaboration tool, a key component of the Digital Asset, helps to meet these challenges by providing a real time collaborative environment which spans global operations, supports and develops synergies between multiple disciplines and transcends geographical and language barriers. Through its use an intentional shift in focus has taken place from centrally located sources of expertise to virtual ones. Virtual centers of collaboration empower users to collaborate, problem solve and share knowledge on demand. Any user, i.e. employee, can rapidly access the global expertise needed to put well challenges, potential solutions and increasing volumes of data and information in appropriate context. Through access to these extended resources employees can solve problems more efficiently and offer better solutions. Technical experts can cover more ground. Collaboration is facilitated by dedicated personnel who maintain a vital link with local, regional, and global technology leaders.Examples from Canada, where the use of this approach contributed to an HTHP well being saved, along with an estimated cost of $15 million, from China where urgent advice was delivered to a rig experiencing an underground blowout and from Brazil where global experts collaboratively contributed to solving a wellbore stability problem will demonstrate how real time collaborative solutions are developed and moved from the virtual to real world environment to improve operational service delivery to external clients in the global market place. Lessons learned, best practices and strategies employed to engage users in the use of this collaborative environment are outlined.

This paper is a review of two recent open hole gravel packed, water injection wells drilled from an offshore drilling rig, with particular focus on the loss of fluids and subsequent control of those losses, and makes recommendations for future wells based on the lessons learned. The techniques and fluids used to drill the deviated interval, place the gravel and remove filter cake prior to flowing back lost fluids and testing injectivity are discussed. The causes of loss of returns at various points during completion operations are identified and the remedial actions taken at the rig site are documented. Suggestions for future operations that should eliminate these losses are also outlined. The drill-in and completion fluids chosen for these operations had to meet several criteria. In particular the bridging particles selected had to be a size range specifically chosen to effectively seal the formation of interest, and quickly form an impermeable filter cake on the surface of the formation, which prevented further invasion by the well bore fluids and subsequent reductions in formation permeability. Once the zone of interest had been drilled, the filter cake had to provide continued fluid loss control during displacements, placement of completion equipment and gravel pumping operations. However, at times potentially damaging losses were experienced. Once the gravel packing operation was complete, it had to be possible to remove the filter cake and bridging particles so that injectivity could be obtained, without plugging or bridging of the gravel pack or completion equipment. The techniques used to control losses also had to meet the same goals of preventing formation damage and avoid plugging of gravel and completion equipment. The experience gained on these two wells shows that careful planning of fluids formulation, drilling practices and completion techniques are necessary to ensure the required fluid loss control while drilling and completing the well, especially while placing gravel. The filter cake formed can then be removed at the desired time to ensure maximum injectivity.

In many cases, the primary waste management challenge facing operators is drilled cuttings generated using oil- or synthetic-based fluids (OBF, SBF). Low temperature thermal desorption units (TDUs) are commonly used treatment systems for removing oil from cuttings. The oil recovered from the thermal desorption process is often reused to make oil-based fluids. However, base oils change during the thermal desorption process, and these changes can have a detrimental impact on the performance of the base oil. In some cases the base oil can break down. Typically the base oil used to formulate an OBF or SBF is selected for economical, drilling and logistical reasons and rarely, if ever, the thermal properties of the base oil. The thermal treatment company is left to determine how best to recover the oil so that the thermal degradation is minimal and the oil is suitable for reuse. To lower energy consumption and preserve the performance of the base oil, it is important to identify a base oil that has either a lower temperature for desorption or higher resistance to thermal degradation during the thermal desorption process. Ideally, a base oil would be chosen that incorporated both properties. The results of this study show that by correctly evaluating and selecting the base oil, the operator can benefit from using a fluid that may be much more suitable for reuse and will require much less energy to thermally treat. This paper describes how to achieve both of these goals using Thermal Gravimetric Analysis, Gas Chromatography / Mass Spec and a low-temperature retort. Determining the optimal desorption temperature is also an important factor. The oils recovered using these methods contain no oxygenated products and exhibit little thermal degradation. Residual oil from on cuttings is less than 1% (w/w). A practical methodology for base oil selection also is included in this discussion. Introduction Thermal desorption technology is designed to produce oil-free (or ultra-low TPH) solids for disposal by distilling off oils from the cuttings and recovering oil to be re-used for drilling fluid. However, base oils can change during the thermal desorption process, and these changes can have a detrimental impact on the performance of the base oil. Highly refined, ultra low aromatic, highly saturated, mineral- or synthetic- based oils may "crack" when exposed to the level of thermal energy required to render cuttings suitable for disposal. The process may also create aromatics and other undesirable unsaturated hydrocarbons that can affect the toxicity of the drilling fluid.1 The use of a base oil with higher resistance to thermal degradation during the thermal desorption process can allow the operator to recover and continue to reuse recovered base oils with minimal impacts on fluid and environmental performance. Modern TDUs have variable temperature control. If the oil on cuttings can be removed at a lower temperature, significant savings can be realized by the operator because less energy will be required by the TDU to reach the required less than 1% residual oil on cuttings. Therefore, it is important to identify a base oil that has a lower temperature for desorption so that it may be effectively removed from cuttings at a lower temperature. A further benefit of the lower temperature will be less inherent thermal degradation of the base oil. The ideal base oil choice would be one with both high resistance to thermal degradation as well as low desorption temperature. This study was conducted to help establish a reliable methodology for selecting the best base oils for use in drilling fluid systems where the thermal desorption process will be used to process cuttings and recover base oil for re-use. Base Oil Screening, Selection and Testing Nineteen base oils were screened using Thermal Gravimetric Analysis (TGA). The screening identified those base oils with a narrow evaporation range and relatively lower boiling points. Base oils were examined in air and under nitrogen; no significant differences were seen between the TGA results for oils in air and those under nitrogen (Table 1).

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