This paper discusses research on how proppant selection affects fracturing treatment results in shale formations that produce high water volumes. Fracturing treatments, formation characteristics, proppant types, and post fracture treatment production results are examined in detail. A production case study that focuses on the impact of proppant selection in wells completed in formations that produce hydrocarbons with a high water cut will also be presented. This paper analyzes laboratory tests that were performed to measure the water and oil flow rates of various commonly used proppants. A case study on how Decreased Water Flow Proppant (DWFP) performed in the Granite Wash in the Texas panhandle is also highlighted. Post fracture treatment production results are compared to traditional proppants used in direct offset wells. Laboratory testing showed DWFP had much lower water flow and higher oil flow through the proppant pack compared to traditional proppants. The results of the laboratory tests will be used to explain and support the production case study. The field case study proves that DWFP reduced formation water production, while increasing hydrocarbon production compared to traditional proppants used in offset wells. This innovative proppant appears to decrease the relative permeability to water in the proppant pack, resulting in lower water production and higher hydrocarbon production compared to conventional proppants. This paper introduces the first proppant specifically designed for fracturing treatments in high water cut reservoirs. A new laboratory test method of measuring water flow rate through a proppant pack was specifically developed for this type of proppant. The proppant’s wettability is introduced as a new proppant selection factor for fracturing treatments in high water cut reservoirs.

In the field practice of alkaline/surfactant/polymer (ASP) flooding, there is more oily sludge produced and accumulated in settling tank, dehydrater, recycling pool, etc. Timely and effective disposal of oily sludge has already played an indispensable role in establishing the surface and subsurface integration pattern with chemicals EOR. Many conventional disposal methods faced to the challenges of separation efficiency, facilities pollution, healthy and environmental threats, and economical justification with the appearance of alkali, surfactant and polymer in produced liquid (mixture of oil and water of wells). We focus on using physical comprehensive effects to remove the emulsified oil and absorbed water, and the in-situ utilization of the left sludge was regarded as a method development to address the challenges recently. A laboratory investigation of characterizing the properties of oily sludge in ASP flooding production was recently carried out. The heating-washing-centrifuging combination treatment process was practiced. After removing its emulsified oil and absorbed water, the sludge transported to filter bed to form a suspended sludge blanket was studied and the feasibility of in-situ utilization of filtering separated water was also evaluated. The application effects of the resource-oriented disposal method were assessed, and the integration technology and operation parameters were designed and optimized. The results indicate that the oily sludge with ASP flooding is characterized by high caloric value, high water cut, high viscosity, strong electronegativity and stability, and there is relatively high melting temperature, more wax and asphaltenes in oil phase. There appears to be a linear relationship between the scale of oily sludge deposition in surface facilities and the appearance concentration of chemicals in produced liquid of production wells. Compared with the previous thermochemistry demulsification disposal methods, dirty oil recovery ratio increased more than 15%, and running expense was reduced around 20%. The dirty oil content in the sludge was less than 2% when disposed under the combination disposal process and operation parameters. Furthermore, the formed suspended sludge blanket has the functions of in-situ purification of separated water, achieving the cyclic utilization in washing process. The probable impacts of its direct discharge into the normal sewage treatment system reduced and secondary pollution decreased spontaneously. This study is beneficial to provide a robust and potential way for disposing oily sludge in the production and operation of chemicals EOR, and it is also significant to understand the surface and subsurface integration idea and further accelerating ASP flooding application in high water cut oilfields.

Drilling operators are facing increased challenges in dealing with the drill cuttings produced due to higher demands from regulatory agencies. Government entities such as the US Environmental Protection Agency (EPA) and Norway's State Pollution Control Authority (SFT) set strict limits regarding the retention of oil on cuttings (ROC) for offshore drilling. This paper describes the role played by the hydrophilic-lipophilic balance (HLB) of a surfactant in designing efficient washing solutions (WS) that utilize both non-ionic and anionic surfactants to mitigate the ROC. A range of anionic and non-ionic surfactant blends was screened for their cleaning ability on field cuttings. The main parameters considered during the surfactant selection were: chain length, branching/linearity, substitution pattern and polarity. For non-ionic surfactants the emphasis was placed on ethoxylated vs propoxylated molecules. Following treatment with WS the ROC was determined by using the retort distillation method (RD) as described in API RP 13B-2. The numbers obtained were graphed against HLB values for the surfactants in order to determine the best correlation between structure and cleaning ability for that particular type of cuttings. The results show the achievement of a maximum cleaning ability of the WS for a given chain length of the surfactants used. The linearity of the molecules, although initially thought to play a significant role, proved to have a limited influence. In fact, blends containing roughly equal amounts of linear vs branched surfactants displayed the highest cleaning ability. The overall polarity of the mixture seemed to be important too, since blends containing non-ionic surfactants had almost no cleaning capacity. Of major importance in this particular study was the substitution pattern on the non-ionic surfactants. An optimum combination of propoxylated vs ethoxylated molecules was critical for the design of the most successful WS. Our results indicate that ethoxylation on the anionic component of the mixture and propoxylation on the non-ionic portion was critical since tests performed with the opposite combination showed almost no cleaning capacity. Increasing the PO content on the non-ionic molecule has a detrimental effect which is more pronounced than a similar increase in EO content on the ionic molecule. The present study aims to help elucidate the roles played by the different surfactant molecules in designing efficient washing solutions for cleaning drill cuttings. This will assist the oilfield service companies in addressing the continuously increasing environmental regulations for disposing of drill cuttings while reducing the present costs and carbon footprint on the environment incurred by the current methods.

For several years now, regulatory agencies including the U.S. Environmental Protection Agency (EPA), energy associations like the American Petroleum Institute (API), and more recently the Center for Sustainable Shale Development (CSSD) have provided recommendations, regulations, performance standards, and guidelines to improve water management in oil and gas exploration. Yet, to fully appreciate the life cycle costs of fluids used for hydraulic fracturing – including water, one needs to examine the total costs of fluid acquisition, management and disposal. Typically, these costs are divided between various groups within an operator's organization (i.e., completions and production), with budgeting emphasis on acquisition costs during the completions process. This paper examines the total life cycle costs of hydraulic fracturing fluids, comparing water-based and energized solutions. It evaluates when fracturing fluids energized with carbon dioxide (CO 2 ) or nitrogen (N 2 ) can be used to reduce water volume for more economical hydraulic fracturing. It also evaluates how the selected fracturing fluid can affect productivity. In certain situations, the increased productivity achieved with energized solutions can more than offset lower per-barrel water costs, driving a lower overall unit cost of production. To approach our analysis, we will look at "A Day in the Life of a Barrel of Water" used for hydraulic fracturing.

Water handling and disposal comprises a significant expense in the drilling, completions, production, and operations disciplines of the oil and gas industry. With the rapid expansion of drilling, completions, and water flooding technologies, designing or redesigning water facilities to meet future conditions is vital. The focus of this project concerned the Monument Butte field in the Uinta Basin of Northeastern Utah, where a five spot waterflood had been implemented and water trucking operations ran for fourteen hours a day. The operator in the region was drilling wells in just over three days, resulting in rapid area expansion. Consequently, water production increased substantially and current infrastructure forced inefficient means of transportation. This increased the lease operating expenses for the operator (LOE). With a limited amount of time, the goal of the project was to provide long and short term solutions to lowering the cost of transportation of water, while minimizing the spread of sulfate reducing bacteria (SRBs). This would then reduce the cost of all operations in the field. Approaching the project involved analytical modeling and field data analysis, while maintaining a mindset to provide a safe environment for all operations. Using production data, a matrix map of deliverables was created to identify regions of high water production and consumption, and to display locations of current water facilities. Water injection wells required a constant flow rate. After daily trucking had concluded and the facilities had discharged all of the production water, fresh water was pumped as a supplement. Using mass balance calculations on the deficit facilities in the areas of high water production, it was possible to see how the addition of incremental stock tanks of varying size would increase the time until a facility reached capacity. This resulted in the trucking of water to other distant locations. Temperatures in this area typically reached negative thirty degrees Fahrenheit in the winter, requiring the insulation and heat transfer calculated burial of truck offload pipes. These offload pipes directed water to the stock tanks. For safety purposes, new offload points were designed to prevent truck drivers from having to backup to unload water. Multiple offload points were needed at some facilities to reduce the wait times on locations. An in-house computer program was used to simulate pressure drops for different scenarios of multiple offload pipe combinations into the stock tanks to make sure the truck pumps would be able to discharge water against the hydrostatics of full tanks. Fail safe actuators were designed with solar panels for the facilities with no electricity or dry gas lines as a power source to ensure the tanks did not overfill. The short term changes to the smaller facilities have shown improvements on trucking and freshwater costs. As a consequence, the advancements have successfully upset neighboring service companies who will be losing unnecessary business. The long term designs are currently undergoing implementation and have high expectations to dramatically reduce LOEs, which can then be delegated to further exploratory needs.

Waste management shall be done comprehensively, starts from waste generator to final disposal. Waste management should base on Reduce, Reuse, Recycle, Recovery, and Disposal (4R+1D) principles. A good waste data management will enable us to promote waste management improvement based on these principles. Waste management data consist of waste recording, waste tracking, and waste reporting. In Total E&P Indonesie, every waste that generate by every entity in each production sites and drilling rigs will be recorded in waste register/Log book. Waste from every site will be transferred to final disposal (senipah) via transit area (handil). Every waste that transfers will be recorded and attached with Waste Transfer Note (WTN) form. Both of this recording system is a paper based systems and has several disadvantages. First, when compiling the waste data from waste register and waste transfer note, there is discrepancy of waste quantity between both of record systems. Second, it needs a lot of man hour to compile the waste data from both recording systems and human error is most likely happen here because of manually recapitulation of waste data which will directly affect the waste data that submitted to authority. Third, it is very hard to track the waste position when transferred, whether it has already arrived in transit area or final disposal because the control paper (Green parts of waste transfer note (WTN) form) often does not come back to waste generator. Total E&P Indonesie developed an application which aim to replace the waste register and waste transfer note and also solving the entire problem that caused by previous systems. This application is an integrated system of waste register, waste tracking, and waste reporting. This application called WISEMan. It has a lot of benefit. First benefit is waste recording, tracking, and reporting will need a short time which can minimize man hours. Second benefit is waste engineer in Total E&P Indonesie can focus on Improving Waste Management that refer to Reduce, Reuse, Recycle, Recovery, and Disposal (4R+1D) Principles, and third benefit is improving awareness of waste segregation to all personnel in TEPI premises because the WISEMan system makes the employee compulsory to segregate the waste that generate by each entity.

North American shale gas plays discovered over the past ten years contain an abundant tcf of natural gas, providing a long term, low carbon domestic energy source. Drilling and completing techniques developed in the Texas Barnett Shale over the past ten years have unleashed an unprecedented new shale gas industry across North America. The most effective completion technique is known as hydraulic fracturing (or "fraccing"), a process that involves injecting a large volume (60, 000 to 140, 000+ bbls) of fresh water underground to fracture the formation, increasing permeability and thus gas flow. After a frac is completed, a large portion of the frac fluid returns to the surface as "flowback" water which contains high concentrations of dissolved salts, frac chemicals, and formation minerals. The costs and logistics of managing both fresh and flowback water in shale gas plays are problematic. Development of North America's shale gas resources will require well developed water management strategies that include the effective implementation of water recycling technologies. Treating flowback for re-use as frac fluid reduces the impact of key issues associated with shale gas water management including cost, truck traffic, water availability, and disposal availability. Factors including salinity, residual frac chemicals (polymers), H 2 S, NORM, carbonate scales, iron scales, and sulphate scales make the treatment and handling of flowback complex. The overall water management strategy is a function of water sourcing and disposal cost and availability, formation geology and how that impacts both flowback water chemistry and frac fluid compatibility, the regulatory environment, and the availability of commercialized and cost-effective technology. This paper explores the challenges associated with treating shale gas flowback for re-use and evaluates the role and cost of available commercial technology. Cases studies of technology applications that have been used during the past seven years in major shale basins will be included.

Abstract In the mature producing offshore fields, managing water production is an important and critical aspect of the oil and gas production. Fields where topside processing facility has reached to its maximum handling capacity, installation of additional equipment require a new approach. Taking a clue from the latest profiles of Indian Offshore Assets which suggest increase in water cut of the order of 70% presently and rising up to 92% by 2030 overloading the process (separation and produced water conditioning) facilities at Process Platforms. This is where project on produced water separation at offshore wellhead platforms was taken up. Water separation at wellhead can be used to: Increase the oil production rate in a pipeline with a given diameter Reduce capacity constraint at separator inlet Develop compact and low weight facilities for marginal topsides With aim to minimize produced water handling at downstream of Wellhead Platform i.e. at process platform, free water is to be knocked out at WHP with Minimum Wellfluid pressure reduction Minimum Floor Space Minimum Interference Maximum reliability Recent developments have made possible separation system meeting strict requirements with respect to both performance and reliability. There are separators operating in subsea environment removing produced water from Wellfluid with desired results. In view of this, the present condition of Mumbai offshore field necessitates the deployment of such techniques in the ageing Mumbai High field as well. This study focuses on produced water separation at offshore WHP and examines the factors affecting separation at unmanned WHP. The study also analyzes the impact of Produce Water Separation at WHP. The possible impacts envisaged are flow assurance, reduced backpressure on wells, wells deliverability, capacity constraint at the Separator inlet and Liquid handling at PWC system of Process Platform. Introduction In the mature producing offshore oil fields, managing water production is an important and critical aspect of the oil and gas production. Fields where topside processing facility has reached to its maximum handling capacity, installation of additional equipments require a new approach. The latest profiles of ONGC's Offshore Assets indicate increase in water cut from 70% presently to 92% by 2030 overloading the process (separation and produced water conditioning) facilities at Process Platforms. Produced water separation at offshore Unmanned Well Head Platform (WHP) is aimed to remedy this problem. Water separation at wellhead can help to:

Abstract The National Oil Company of Trinidad, which has operations throughout the south of the island, currently produces 35,000 barrels of water per day (bwpd). While every effort is being made to ensure conformity before discharge, there are twenty-eight (28) parameters which have to be addressed immediately. The new legislation in the country requires all companies conform to the specification laid down by the Environmental Management Authority (EMA). Conventional primary and secondary technologies currently in use, do not allow us the capability to address these parameters. An evaluation was carried out on two types of technology namely the membrane filtration/reverse osmosis, and the electro coagulation/variable vacuum distillation. The introduction of either technology can assist companies with oil field operations on land in Trinidad to conform to the required specification. If the use of the technology is costly, then arrangement can be derived from a service company to provide the facility and seek alternate arrangement as to recover the cost of the operation.

Abstract Friction-based thermal desorption, with temperatures between 260 and 300°C, allows the oil and water phases to be volatilized and subsequently condensed and recovered, leaving dried and cleaned solids that can be disposed. Frictionbased thermal desorption reduces the residual oil on the cuttings while recovering oil and other materials for reuse. This paper presents the novel friction-based thermal desorption system currently deployed in the relatively hostile and remote Koshken area, located on the steppe escarpment above the eastern shore of the Caspian Sea, Kazakhstan. This project is expected to produce 50,000 tonnes of oil-based drilling fluid or "mud" (OBM) drill cuttings annually, which must be treated to below 1% TPH oil before disposal. Any treatment technology utilized in this environment faces operational and logistical challenges, including the severe climate and the need to transport the drill cuttings from an offshore facility to an onshore centralized location. Improvements in friction-based thermal desorption technology were developed specifically for the Koshkani project to ensure health, safety and environmental (HSE) compliance and allow a best-in-class system to operate in this harsh environment. In this paper, the authors describe the three-year development process, from initial design and equipment construction through installation, commissioning and operation. Analytical data presented includes analysis of discharged material, recovered base oil and air emission analysis. A comparison is made between the application of thermal desorption technology and alternative technologies used in similar projects. Friction-based thermal desorption met increasingly high performance expectations and technology advancements allowing them to be achieved with assured HSE performance. Given the environmental performance that the Kashagan project required, this technology has proven to be the simplest, easiest and most effective system to implement in this environment with assured success. Introduction Thermal desorption of drill cuttings was introduced to the oil industry in the early to mid 1990's, following the successful treatment of contaminated soils from industrial activities. Since then, thermal desorption has evolved into an acceptable technology for treatment of drilling wastes from both from onshore and offshore operations.1–3 Offshore discharge of oilbased drilling waste (drill cuttings and used drilling fluids) generally is not acceptable because of the environmental impacts. For a large fraction of the drilling operations, transport onshore for treatment and/or disposal is the only appropriate solution. In thermal desorption, heat is added to a material resulting in a temperature rise above the boiling point of the volatile compounds in the material. By subsidiary cooling of the vapors, the volatile compounds can be recovered and fractionated. Sufficient vapour pressure is generated such that the volatilized compounds are separated from the host matrix. In oil-based drilling waste the main volatile compounds are the base oils and the water from the drilling fluid. For separation of drilling waste into reusable base oil, and in the same process reach a residual oil level in the solids that meets common standards for disposal or alternative use, thermal desorption has proven to be both environmentally and commercially acceptable. The Kashagan drilling programme utilised oil-based fluid (OBM) for the Caspian Sea wells. The expected 50,000 tonnes of drilled cuttings contaminated with OBM not only required treatment to lower the discharged recovered solids to below 1% Total Petroleum Hydrocarbons (TPH), but also the recovered oil had to be of the highest standard available.

ABSTRACT An environmental scorecard is being developed to determine the tradeoffs associated with implementing low impact drilling technology in environmentally sensitive areas. The scorecard will assess drilling operations and technologies with respect to air, site, water and biodiversity issues. Low environmental impact operations will reduce the environmental footprint of operations by the adoption of new methods to use in (1) getting materials to and from the rig site (site access), (2) reducing the rig site area, (3) using alternative drilling rig power management systems, and (4) adopting waste management at the rig site. The scorecard enables a dialog to be established and maintained among all interested, concerned and affected stakeholders. In this manner, the oil and gas industry has a new way of seeing itself within the larger network. The scorecard presented in the paper provides the means to demonstrate the connectivity between energy production and the affected ecosystem. The Houston Advanced Research Center (HARC) and Texas A&M University have been leading an industry consortium effort to investigate the development of low impact drilling systems. The work originated in 2005 and funding was obtained by the U.S. Department of Energy for 2006 through 2008. The goal of the low impact drilling systems project is to reduce the environmental impact of rig operations through integration of low impact site access and site operations. The paper will discuss the scorecard that is being developed. The scorecard methodology presents an ecological understanding of the tradeoffs associated with producing energy. The EFD scorecard will be developed in detail for a coastal margin ecosystem and the methodology will be documented to enable the scorecard to be replicated at other ecosystems wherever reservoirs are produced. This scorecard methodology is being developed through a series of workshops being held with ecologists, botanists, wildlife management experts and others in addition to oil and gas industry experts. INTRODUCTION The Houston Advanced Research Center (HARC) and Texas A&M University through the Global Petroleum Research Institute (GPRI) have been collaborating with industry and environmental organizations to integrate and demonstrate current and new technology into land-based drilling systems for compatibility with environmentally sensitive or off-limits areas. The Environmentally Friendly Drilling Systems (EFD) Program is taking a systems approach to the integration of currently known but unproven or novel technology in order to develop drilling systems that will have very limited environmental impact and enable moderate to deep drilling and production operations and activity with reduced overall environmental impact. The EFD Program is identifying and providing the technology to successfully produce shale gas and tight gas sands while appropriately addressing environmentally sensitive issues. The project focuses on developing drilling technologies that can be used throughout the U.S., in particular, unconventional natural gas resources as illustrated in Figure 1 and Figure 2.

This paper was presented as part of the student paper contest associated with the Annual Technical Conference and Exhibition. Abstract In the ‘sweetening’ of natural gas, many waste byproducts are created; among these wastes is H 2 S. In this work the injection of pure H 2 S into a deep aquifer as a means of disposal and sequestration has been studied using a compositional numerical reservoir simulator. The primary concern of this study is the evolution of the area of influence of the H 2 S gas front through the aquifer. The study incorporated a sensitivity analysis to determine which parameters have the greatest effect on the area of influence of the gas. Once this is established, those that are controlled parameters may subsequently be optimized, and those that are aquifers properties may later become part of a selection process in choosing aquifers for H 2 S disposal. This will also determine which properties of an aquifer must accurately be tested in order to better predict the area of influence and behavior of the gas. Introduction Several reservoirs contain sour gas, a blend of natural gas and H 2 S, either alone or in combination with CO 2 . In order to meet specifications for gas sales, the H 2 S and CO 2 need to be removed from the produced gas at gas plants. In recent years, environmental regulations have become increasingly strict, particularly in the management and disposal of the waste products of the ‘sweetening’ of natural gas. Conventionally the removed H 2 S is converted to elemental sulfur by means of a modified Claus Plant. 1 The efficiency of this conversion process is shown to vary depending on the ratio of CO 2 to H 2 S present in the removed acid gas. This has a direct effect on the amount of SO 2 flared as waste from the process, one of the least environmentally friendly aspects of this conversion. Another concern involves the produced sulfur; for many years the supply of elemental sulfur has significantly exceeded the demand, resulting in stockpiles of unused sulfur. 2 Sulfur reacts vigorously with air to produce SO 2 , and if not securely stored, the production of SO 2 may escape to atmosphere, resulting in greater environmental concern. With so many possible environmental concerns in the traditional method of managing H 2 S from natural gas, added to the typically low selling prices of the resultant sulfur, new strategies have been considered. Such strategies are aimed to be more environmentally sound and decrease associated costs with disposal. Included in alternate management and disposal strategies is the acid gas injection into deep aquifers, which has been gaining popularity in recent years. In this approach, a suitable aquifer must be selected in which environmental impact will be minimal and optimal parameters for injection must be established. The possible sources for environmental impact include migration of the gas to nearby, particularly overlying, formations and eventually back to the surface, and undesirable reactions with formation water or rock. The possibility of these outcomes must be investigated to establish the feasibility of this disposal strategy. In this work, one particular case study has been considered to investigate the acid gas injection strategy, considering pure H 2 S. The foundation of this case study is the development of a base model. Once the results of the base model were established, a sensitivity analysis was performed. The objective of the sensitivity analysis was to determine the discrepancy in resultant data based on the uncertainty in formation parameters such as anisotropy ratio and variation in controlled parameters such as perforation location. The results of these variations provides a range of outcomes that may be expected from the implementation of acid gas injection in order to ascertain whether there will be any significant environmental impact in the specific case being studied. It is hoped that this work will result in implementation of the disposal method in the case considered. The targets of the sensitivity analysis may also lead to research into the establishment of selection criteria for suitable aquifers for further disposal of acid gas.

Abstract As part of the well planning process, the professional drilling engineer is confronted with the issue of drilling waste management.Frequently, the drilling engineer has little or no experience or training to deal with the variety of issues involved with drilled cuttings and waste drilling fluid disposal.Waste management is also becoming a larger part of total drilling costs and poses definite potential future liabilities to the operating company.One of the ways to fill this need without formal training is to provide the untrained engineer with computer software based on previous experiences.In this manner the untrained engineer can learn on-the-job without costly mistakes due to inexperience. This objective of this paper is to discuss recently developed computer models that address drilling waste management issues.Some of the models discussed are: Solids control efficiency Waste volume/mass generation Pit sizing for onshore waste collection Box needs for waste transportation Technical feasibility of offshore disposal options Liability associated with disposal options Cost of offshore disposal options Treatment requirements for disposal or re-use options Land requirements for land application of drilled cuttings While computer modeling is not new, the application of it to drilling waste management is certainly new.For instance, a bonus-malice system is used to evaluate liability and feasibility associated with offshore disposal options.This allows more realistic evaluation of disposal options.A second innovation is in the use of reverse-wave engineering.Applied to drilling waste disposal, the final disposal or re-use option is selected and treatments are suggested that meet the input and disposal criteria. While the obvious advantage is to provide artificial intelligence to the user, there is another major advantage to software approaches to drilling waste management.The computer-based approach allows multiple, rapid evaluations of complex variables.The relationship between drilling parameters, waste handling, treatment, and disposal options can be better examined. Introduction Recently, emphasis has been placed on developing computer software "tools" to help the drilling engineer with drilling waste management planning.These programs vary from performing simple to complex calculations.There are also programs that use experience bases to simulate artificial intelligence.One free website provides links to environmental regulations in the United States, as well as other services.1 This paper discusses a number of programs that are available.Together these programs form a useful function.Engineers not formally trained in drilling waste management can use the tools to gain experience.Planning engineers can also use the tools to run multiple "what if" cases that would otherwise be laborious. Many of these programs are simple calculations, but several of them use the latest in programming technology.Reverse wave engineering and bonus-malice evaluations are integral parts of some of the programs. Discussion Solids control efficiency is an important drilling parameter affecting mud usage and waste generation.It can also affect drilling rate, which impacts overall drilling cost.It would seem natural, then, that some form of solids control efficiency prediction model should exist. One simple model was suggested by Manohar Lal2.Mr. Lal's research suggests that particle size delivered to the solids control system is largely determined by the type of formation drilled with only minor changes dependent on other factors.The information on particle size distribution relates to the particle sizes that can be removed by solids control devices.This is shown in Figure 1.

Abstract The increasing environmental legislation surrounding drilling operations has led to a rapid rise in drilling waste management spending by operators.The traditional perception has been that this increased spending adds to well construction costs.While it true that new technology comes with a price tag, and much of the technology used in drilling waste management has been introduced in the last 10 years, many technologies now available to operators are clearly cost effective when the entire well construction cost is evaluated. The cost of making a mistake and having either an expensive remediation project or a potential liability nearly always significantly outweighs the cost of a good preventative drilling waste management program.Further, compliance with current environmental regulations does not always guarantee immunity in the future. The correct deployment of both new and traditional drilling waste management technologies is reviewed in several case histories taken from the global operations of a major service company. The paper demonstrates that the correct application of these technologies combined with a holistic approach to drilling waste management and drilling fluid operations results in a net reduction in well construction costs and a reduction in the potential for environmental liability. Introduction Drilling waste has traditonally been defined as drill cuttings and excess drilling fluid1 and these certainly comprisethe vast majority of drilling waste.Other materials generated by drilling operations can include contaminated water, material and chemical packaging, emissions such as carbon dioxide, scrap metals, fuel, lubricants and other oils as well as the usual human and industrial wastes associated with any camp or offshore facility. For the purposes of this paper the focus will be on drill cuttings and excess or spent drilling fluids and the treatment and or disposal of these waste products at the end of the well or wells in compliance with the governing regulations for the area of operations. All the costs associated with that treatment and disposal are usually considered as part of the overall well construction costs.Evidence from the representative case histories presented here demonstrates that correct waste management and the right technology applications can actually reduce, rather than increase well construction costs. The reasons for this are explored in the paper. Timeline of Drilling Waste Management Up until the 1980s there was little or no drilling waste management as we know it today.The excess cuttings and fluid were typically discharged overboard in offshore operations and spread on the lease sites or buried in land operations.At this time there was generally little, if any, legislation regarding the disposal of these materials.Discharge and landspreading were low cost solutions that also allowed the operator to remain in compliance with existing regulations.Therefore the the actual of amount of waste generated and was subsequently disposed of was of little consequence or interest to the operator or service company. In fact it was argued it was detrimental to the service company to reduce the amount of fluid and waste generated as these volumes were the primary method of compensation. In the 1980s and early 1990 global awareness and understanding of environmental issues was significantly increased. The impact of drilling operations and in particular drilling waste became a subject of interest to operators, service companies and regulators.The early regulations typically restricted what could be disposed of by setting limits on oil content or chloride content or the location of proposed disposal sites in reference to the water table and local environment, etc.The types of fluids being used also came under closer scrutiny and the toxicity of fluids and cuttings was evaluated and regulated.\

Abstract The need for paying close attention to the environment has been of paramount important since the introduction of specific environmental legislation (for example the Environmental Management Act 3/2000) in Trinidad and Tobago. Out of the Environmental Management Act, several pieces of legislation have been drafted to better regulate the industry and include: Environmentally Sensitive Areas and Species Rules Noise Pollution Rules Certificate of environmental Clearance Rules Air Pollution Rules (Draft) Water Pollution Rules (Draft) The only shortcoming is that there are presently no solid and hazardous waste management rules in Trinidad, and the Environmental Management Authority is currently in the process of planning for the development of the rules for the entire country and by extension, the petroleum industry as a whole. The approach to date has been the focus on a simple piece of legislation to govern all industrial sectors. While this may be an approach to the management of common types of wastes encountered in all industrial sectors, it may not be practical for the petroleum industry. Developing a model and testing it against practical data for the petroleum industry can only be the practical way the legislation would be meaningful to the industry. Introduction In Trinidad, the need for a more care and attention to the environment is urgently needed. Although the Environmental Management Act 3/2000 has become law with the need for a Certificate of Environmental Clearance before any new plant can be built, there is still no urgency to move the requirements forward. Attempts are being made to move the legislation forward. The paper undertaken examines the development of a model and evaluating it against the generation of hazardous waste in an area serviced by several facilities and industries. St Patrick County, located at the south-west peninsula (see Figure 1) of Trinidad was chosen to carry out a feasibility study in developing a landfill to handle hazardous waste. In this county there are several industries that co-exist and the amount of waste generated need to be disposed of properly. The information derived from the area would be used to test the model being proposed. Hazardous wastes are substances intended for disposal, recycling, or recovery that can harm people, plants, animals, or the environment. Properties of Hazardous Waste Waste is hazardous and a recyclable is a hazardous recyclable waste if, when tested: it has a flash point of less than 61°C, it ignites and propagates combustion in a test sample, it contributes oxygen for combustion at a rate that is equal to or greater than that provided by ammonium persulphate, potassium perchlorate or potassium bromate, it is toxic because it has an oral toxicity LD50 not greater than 5000 mg/kg, has a dermal toxicity LD50 not greater than 1000 mg/kg, or has an inhalation toxicity LC50 not greater than 10,000 mg/m3 at normal atmospheric pressure, it has a pH value less than 2.0 or greater than 12.5, it contains polychlorinated biphenyls at a concentration equal to or greater than 50 mg/kg, or it is a toxic leachate because it is in a dispersible form and it contains any of the following substances in a concentration greater than 0.001 mg/L: hexachloro-dibenzo-p-dioxins, pentachloro-dibenzo-p-dioxins, tetrachloro-dibenzo-p-dioxins, hexachloro-dibenzofurans, pentachloro-dibenzofurans, tetrachloro-dibenzofura

Abstract The Ameriven Central Waste Treatment Facilities (CTRD Centro de Tratamiento y Recuperación de Desechos ), which were designed and implemented with the technical support of teams provided by a major drilling waste management service company, receives and processes heavy-oil drilling and production waste generated by operations in the Hamaca Project, located in the Faja Region of the Orinoco Belt in Venezuela. The CTRD operational strategy emphasizes the 4Rs: reduction, reuse, recovery, and recycling. Important cost savings have been achieved from: the consolidation of waste treatment at one location near the source; and the efficient waste management practices implemented by the fluids and waste management team, under contract with Petrolera Ameriven (Ameriven). The facility now serves as a model for similar operations in the region and has earned unconditional approval from governmental agencies and prominent companies with commercial interests in the area's forests and resources. Over the life of the 30-year project, the facility will process the waste from approximately 250 to 500 wells. The current development production phase yields 80,000 bbl/day, with 190,000 bbl/day extra-heavy crude expected in the commercial production phase. Cost reductions related to waste management and disposal at this site are currently estimated at 22% (since commencement of operations) and are expected to improve further as the facility is used to full capacity. Several integrated processes are implemented for the efficient disposal of drilling waste products: thorough rig audits, solids-control equipment performance, rig, field, and plant supervision, dewatering, water treatment, and landfarming and landspreading of processed solids and cuttings. Introduction The Ameriven Central Waste Treatment Facilities (CTRD Centro de Tratamiento y Recuperación de Desechos ) were installed in 2002 to process heavy-oil drilling and production waste generated by operations in the Hamaca Project, located in the Faja Region of the Orinoco Belt in Venezuela ( Fig. 1 ). Over the life of the 30-year project, the facility will process waste from 250 to 500 wells. The current development production phase yields 80,000 bbl/day, with 190,000 bbl/day extra-heavy crude expected in the commercial production phase. The CTRD operational strategy emphasizes the 4Rs: reduction, reuse, recovery, and recycling. Important cost savings have been achieved from: the consolidation of waste treatment at one location near the source; and the efficient waste management practices implemented by the fluids and waste management team, which is under contract with Petrolera Ameriven (Ameriven). The facility now serves as a model for similar operations in the region and has earned unqualified approval from governmental agencies and prominent companies with commercial interests in the area's forests and resources. Since the CTRD project startup, the overall cost of drilling fluid and waste management has dropped 36%. At the time of this writing, 109,088 bbl of crude oil, valued at over U.S. $1million, have been returned to the Central Operating Base (COB). Before the CTRD was installed, the volume of crude oil would have required disposal at an extremely high cost ( Fig. 2 ). Achieving the 4Rs The CTRD facility has processed the waste from 87 wells at the time of writing. Both drilling and production waste streams have been processed. The drilling waste stream comprises cuttings, drilling fluid, oil contamination in the drilling fluid, cement, and spacers. The production waste stream comprises completion fluids, oily sludge from tanks, equipment, and pipelines, and contaminated soils resulting from any spill situations that may occur.

Abstract The use of diesel to formulate onshore drilling fluids has been ubiquitous in North America. Recently however, a number of operators have abandoned using diesel in favor of more environmentally acceptable fluids such as those afforded by waterbased drilling fluids or high paraffinic fluids. The latter type are especially useful in high temperature, high pressure extended reach applications. In addition, the newer all-paraffinic fluids possess reduced toxicity and reasonable biodegradability characteristics. As such, they are excellent candidates for a variety of drilling applications and for cuttings remediation approaches including composting. Introduction Whereas the technology of waterbased fluids has improved over the years, the operational advantage and robustness of oil based muds continue to make them inherently superior to their waterbased counterparts. At the same time, the environmental, human health and safety characteristics of many of the oils available to the industry leave much to be desired and can be source of future financial liability. Furthermore the handling and disposal of cuttings formed with lower quality, high aromatic oils such as diesel, is highly problematic. To address this need, many operators in Canada have turned to using very high paraffin fluids which offer all of the operational advantages of traditional diesel based fluids without the human health and safety and environmental downsides. Paraffinic Fluids - Physical and Compositional Characteristics The physical characteristics of the very high paraffin (or VHP) fluids used in Western Canada are shown in Tables 1 and 2. Whereas diesel is manufactured to relatively broad physical specifications with little regard for chemical makeup the VHP fluids are manufactured to very tight physical and chemical characteristics. The compositional variation of diesel adds another dimension of complexity to the formulation of muds, as well as to the disposal of drill cuttings. Past performance achievements cannot always be realized or relied upon to predict future events with any degree of accuracy. The other areas affected by compositional variations are environmental, as well as human health and safety issues, which correlate to the levels of aromatic impurities and the low boiling constituents. Because of diesel's inherent variability the diesel data shown in Table 1 should be viewed as representative of the group. The VHP fluids are made to two viscosity grades - 2.9 and 3.4 cSt@40°C. The pour points of the paraffin fluids vary from –30°C to –21°C. Although the latter pour point is somewhat high for Canadian winter conditions it can be adjusted downward through the use of a small amount of appropriate pour point depressant technology, as shown in Table 3. Testing results have shown that the pour point depressant is neutral with respect to the final mud properties and drilling performance. The VHP fluids have inherently better volatility and flash characteristics than a typical diesel. Furthermore, the flash characteristics of the VHP fluids were greater than 93.3°C as determined by the closed cup (or Pensky Martin) method. This means that unlike diesel, the high paraffinic fluids are not deemed to be controlled substances according to WHIMIS or OSHA for flammability. From a human health and safety consideration, the lower volatility of the VHP fluids is very important. Some of the low boiling aromatic molecules are especially aggressive to skin, eyes and the respiratory track and generally contribute to the discomfort felt by rig operators working on the handling and disposal of drill cuttings.

Abstract The Ishpingo-4 and Ishpingo-3 wells were drilled by Petroecuador - Ecuador's state-owned company - in the ITT (Ishpingo-Tiputini-Tambococha) field. This field is located in the Yasuní National Park in the Ecuadorian Amazon region, which was declared a World Biosphere Reserve by UNESCO in 1989. The Ishpingo wells were drilled primarily to delineate oil reserves, and the project was managed by Petroecuador and PETROBRAS ENERGIA S.A. (PE)professionals. PE contributed recent experience gained from drilling two appraisal wells, Apaika 1x and Obe 1x, across the lease line. These wells were drilled and tested within the same natural life reserve area with similar heliborne equipment, materials and personnel. To operate in this highly sensitive area, PE and Petroecuador developed a specific Environmental Management Program (EMP) that actively involved environmental authorities and representatives from native communities. The EMP was prepared using the PE Integrated HSE Management System certified by ISO14001 and OHSAS 18001. To assess the results, audits were jointly conducted by the Ecuadorian government, the native communities and the company. In 1992, two vertical wells - Ishpingo-1 and Ishpingo-2 - were drilled in the Ishpingo field. The additional appraisal wells were planned with extended reach trajectories from existing well locations to minimize environmental impact. The logistics, drilling and testing of the two high-angle wells were operationally successful, and the geological target was reached to confirm hydrocarbon occurrence and reserve size. Ishpingo-3 set records in Ecuador as the steepest dip well drilled in a 16-in. section and the steepest dip well out of all high-angle wells drilled in that country. The high-viscosity crude oil - 12° API - as well as the high-deviation angle of the wells prevented the use of conventional testing techniques. Therefore, special methods, together with state-of-the-art directional equipment, were employed to determine both deliverability and reservoir boundaries. The effective application of these technologies, with optimum allocation of there sources and good terrestrial-fluvial-aerial logistics, resulted in a highly successful operation overall. Introduction The ITT (Ishpingo-Tiputini-Tambococha) blocks held by Petroecuador and Block31 held by PE are located in the Yasun National Park (YNP) in the EcuadorianAmazon region. This park was created by the Ecuadorian State in 1979 and wasdeclared a World Biosphere Reserve by UNESCO in 1989. YNP is the Ecuadorianprotected area exhibiting the highest degree of biodiversity, includingamphibians, reptiles, mammals, fish and invertebrates. In addition, the numberof plant species in the YNP makes it Ecuador's second most important regionwith regard to flora diversity per acre. Because of its large spatial area ( Fig. 1 ), the YNP can host healthyand stable stocks of any species over time (1999 YNP Strategic ManagementPlan). Most of the area covered by the blocks within the park consists ofpermanently or temporarily flooded forests. Vegetation consists of primaryforest with isolated human settlements. The park temperature ranges from 24° to26°C with 77% to 88% humidity, and precipitation exceeds 12,000 mm/yr. The YNP is inhabited by Quichua and Huaorani peoples. The Huaorani make up atribal community whose origins or historical references are unknown. The Kawimeno settlement dates to 1982 when the Taparon Anameni community, later known as Garzacocha and currently as Kawimeno, was founded with the help of the Capuchinos Mission. This is the only community near the project, located on thebanks of the Yasun River, which runs SW of the confluence with the Pindoyacu River. In 1992, two vertical exploration wells - Ishpingo-1 and Ishpingo-2 - were drilled by Petroecuador to 6190 ft (1887 m) and 5980 ft (1823 m), respectively. Oil was found in the Basal Tena, U and M formations. The fields contain heavy crude oil (12° to 14° API), and the wells are temporarily abandoned.

Abstract Since its first use about 15 years ago, drill cuttings injection has grown to become a routine operation performed around the world. This rapid development is due to increasingly stringent environmental regulations and improved costs compared to alternative disposal options. The regulations for overboard discharge of cuttings started with limitations on oil-based muds and has now expanded to include synthetic muds as well. The economics of injection operations have improved as the industry has gained experience with the technology, with added benefits from the economies of scale offered by large capacity injection facilities. The two critical engineering questions that must be answered for injection applications are: where does the waste go and how much can we safely inject into a well? These questions require integration of a variety of environmental, technical and economic factors that are important for each particular injection operation.The geometry of hydraulic fractures created during solids injection is one of the key issues in most operations. This coupling between solids injection and fracturing is the focus of this paper. Introduction Cuttings injection began in the mid-1980's with small volume annulus injection in the Gulf of Mexico. 1,2 By the early 1990's, it had already gained broader use in the GOM 3 , the North Sea 4 , Alaska 5 , and for NORM (Naturally Occurring Radioactive Material) disposal 6 . In the mid-1990's, the first large commercial facility with dedicated injection wells began operation 7,8 . This was followed by large-scale injection operations in Alaska 9 and the Gulf of Mexico 10,11,12 . At present, annulus injection is available for routine use offshore, with several different service companies providing a range of operations and engineering support. An example of the continued evolution of the technology was documented in a 2002 study on commingled drill cuttings and produced water injection 13 . The two most common sources of waste injected are from ongoing drilling operations and from mud and cuttings that have been temporarily stockpiled pending some future permanent disposition. Cuttings from an ongoing drilling operation are usually retrieved from the shale shaker, mixed with water, processed to an appropriate size and injected downhole. In the US Gulf of Mexico, for example, over 1000 wells were drilled in 1998. Each one of these wells generated cuttings commensurate with the hole-volume drilled, usually at least 1000 barrels of solid cuttings, or about 3000 barrels of slurry. By comparison, there are only a few locations where cuttings have been stockpiled, but the volumes in these sites are enormous. On the North Slope of Alaska, cuttings from wells drilled in the 1970's and 80's have been stored in reserve pits at dozens of drill sites. By 1993, the stored volume had grown to about 5 million cubic yards of mud and cuttings, or about 15 billion pounds of solid cuttings . The ability to inject solids depends primarily on the subsurface geology, with the chemical composition or physical properties of the solids a secondary factor. For drill cuttings injection, the solids will consist of rock from whatever geologic section has been drilled: this could be sandstone, shale, limestone, coal, dolomite, etc. Cuttings will always contain some residual mud carry-over, including the base mud, plus any fluid loss additives, polymers, barite, etc.All these can be readily processed and injected. In addition, NORM solids have been injected in both small annulus injection batches and large volume dedicated injection wells. If regulations allowed it, both non-hazardous and hazardous solid waste can also be injected.

Abstract The process of drilling oil and gas wells generates large volumes of drill cuttings and spent muds. The American Petroleum Institute estimates that in 1995, about 150 million barrels of drilling waste was generated from onshore wells in the United States alone. Onshore and offshore operators have employed a variety of methods for managing these drilling wastes, depending on what state and federal regulations allow and how costly those options are for the wells in question. In the offshore, the options are limited to discharge, underground injection, and transport back to shore for disposal. Onshore operators have a wider range of options— some wastes are managed onsite while others are removed to offsite commercial disposal facilities. The onshore waste management options employed include landspreading and landfarming, evaporation and burial onsite, underground injection, incineration and other thermal treatment, bioremediation and composting, and reuse and recycling. Some drilling waste management practices used in the past did not protect the environment and public health to the extent desired and were later prohibited by regulatory agencies. This paper reviews some of those past waste management practices and indicates how wastes are currently being managed. Over time, state and federal regulatory requirements will become stricter, drilling and mud system technologies will advance, and some companies may voluntarily adopt waste management options that have even less environmental impacts that those in use today. The paper also discusses some possible drilling waste management practices that are likely to be employed in the upcoming decade. Introduction The well-drilling process generates two types of wastes — used drilling fluids and drill cuttings. Drilling fluids (or muds) are used to aid the drilling process. Muds are circulated through the drill bit to lubricate the bit and to aid in carrying the ground-up rock particles (drill cuttings) to the surface, where the muds and cuttings are separated by mechanical means. Most onshore wells are drilled with water-based or oil-based muds, while offshore wells may also use synthetic-based muds. The American Petroleum Institute (API) 1 estimates that about 150 million barrels (bbl) of drilling waste was generated at U.S. onshore wells in 1995. Purpose Oil and gas wells have been drilled for over a century. In the early years of the industry, little attention was usually given to suitable management of drilling wastes. The purpose of this paper is to review the past waste management practices and indicate how wastes are currently being managed. Over time, state and federal regulatory requirements will become stricter, drilling and mud system technologies will advance, and some companies may voluntarily adopt waste management options that have even less environmental impacts that those in use today. The paper also discusses some possible management practices for drilling wastes that are likely to be employed in the upcoming decade. The U.S. Department of Energy (DOE) is responsible for ensuring an adequate and affordable supply of energy for the nation. One of DOE's goals is to identify and support new technologies that help oil and gas at lower cost and with less environmental impact. The author has evaluated many waste management technologies and strategies for DOE throughout the past decade. Some of these are included in the following discussion.