Cuttings Re-Injection Research Articles

Environmental and living organisms’ disaster caused by discharge of drilling fluid waste

The oil and gas industry plays a vast and vital role in our society. Despite the numerous benefits of the production of crude oil, its activities pose a lot of dangers to the environment and living organisms because it generates a huge volume of solid and liquid wastes, thus, these wastes require treatment before disposal. The major drilling wastes are drilling muds, drilling cuttings, and obnoxious gas emissions. Parameters that should be considered during the disposal of decontaminated drilling muds and drill cuttings are heavy metals. These wastes are introduced into the environment through accidental spills as well as intentional discharge. The discharge into the environment has effects on humans, plants, birds, soil, and also aquatic life. Generally, oil based drilling fluid usage and disposal are not preferable. However, water based drilling fluid and synthetic based drilling fluid can be a technically and economically disposed because they are biodegradable. Generally, drilling waste disposal options are offshore disposal, onshore disposal and drill cuttings re-injection. Zero discharge can achieved by drill cuttings re-injection. However extensive study must be carried before drill cuttings can be re-inject to the formation. Disposal options must be evaluated based on economics, environment and operational aspects. This study aimed at evaluating the heavy metals present in the drilling fluid waste and drilling cuttings. The experiment was achieved with the aid of a Flame Atomic Absorption Spectrophotometer (FAAS). Upon the investigation, it was discovered that lead concentration in drilling cuttings was the highest with the concentration of 1,058.9 mg/l and drilling fluid was 190.3 mg/l whereas NUPRC limit is 5 mg/l; the total chromium concentration in drilling cuttings was 19.16 mg/l and drilling fluid was 8.38 mg/l whereas NUPRC limit is 8 mg/l; zinc was 58.10 mg/l in drilling cuttings while in drilling fluid it was 23.96 mg/l whereas NUPRC limit is 50 mg/l; silver concentration in drilling cuttings was 14.67 mg/l and drilling fluid 0.91 mg/l whereas NUPRC limit is 5 mg/l; Cadmium concentration in drilling cuttings was 2.17 mg/l and drilling fluid was 1.36 mg/l whereas NUPRC limit is 1 mg/l. In no doubt. The study has shown that disposal of this drilling fluid waste and drilling cutting directly into the environment without treatment will be detrimental to the living organisms and therefore should be discouraged.

A novel method for preventing technical challenge during drilled cuttings/produced water reinjection: An injection rate management tool

Drilled cuttings reinjection (DCRI) is arguably the most cost-effective technique for disposing of drilling wastes, especially under the zero-discharge policy. However, there are many failed operations due to technical issues related to surface pumps and annular pressure. Currently, there is no sophisticated model for predicting an optimum injection rate that prevents technical failure during DCRI. The practice of using an arbitrary rate is not based on sound engineering principles and may be unable to prevent annular or pump failure. This is because operators do not relate the injection rate to the Maximum Allowable Surface Pressure (MASP) and/or the Maximum Allowable Annular Surface Pressure (MAASP). Due to these limitations, operators seek to find new methods to handle DCRI through the annulus. Thus, this study was carried out to derive a model systematically for the optimum injection rate to prevent technical challenges during DCRI. The components combined include the mechanical energy balance (MEB) and the model for hydraulic horsepower (HHP). The MEB between the wellhead and the annulus was used to derive a model for the annular pressure. Mechanical equilibrium between the STP and the MASP was used to generate another equation, based on the HHP. Then, the new expression was substituted into the annular pressure model. Lastly, the optimum rate was derived based on mathematical principles. The results applied to Well B of the Niger Delta showed a value (2.95 Bbl/min or 675.37 m3/day) that is consistent with the existing field database, and outperformed other related models for flow rate. Simulation results showed that the annular size (78.8%), rheological parameters (12.4%), and MASP (2.9%) were the main factors that affected the optimum injection rate. Thus, we can apply a higher injection rate in larger annuli compared to smaller ones, and to maintain annular pressure simply ensure uniform annulus devoid of erosion/thermal effects.

Optimization of cuttings slurry system for re-injection of oil-based drilling cuttings

ABSTRACT Cuttings re-injection technology has become a preferential choice of the treatment of oil-based drilling wastes in offshore oilfields. However, there are relatively few formulation designs and performance tests for re-injection slurry systems. In this study, an oil-based drilling cutting re-injection fluid system was developed. The relationship between the suspension and rheology of the re-injection fluid and time is obtained by using the experimental method of sectional measurement. The laboratory re-injection fluid preparation procedures are introduced in detail. The final optimized cutting slurry has a formula for drilling cuttings content of 15% −35%, guar gum (GG) content of 0.4% as the main additives, and auxiliary additives such as 0.3% fluid loss agent and 0.3% defoamer. The experimental results show that the re-injection fluid has good suspension and rheology. After standing at 60°C for 24 h, the sedimentation density difference is only less than 0.12 g/cm3, and the viscosity is 51–66 mPa·s. The cross-linked structure of the internal molecules of the fluid system remains stable, and the viscosity does not decrease obviously to the increase in time. The overall performance of the optimized re-injection fluid satisfies the requirement of the operator.

Technology Focus: Hydraulic Fracturing Modeling (November 2022)

Hydraulic fracture stimulation is proven to be the economic way to develop tight unconventional reservoirs. From an operational perspective, hydraulic stimulation is well established and widely applied to most unconventional plays. There is still room for improvement, however, to increase the efficiency and deepen the understanding of the detailed mechanism in the process. Particularly in the domain of fracture simulation, significant effort has been devoted to enhance model complexity and accuracy. Recent simulation studies have covered sophisticated mechanisms such as hydraulic fractures—natural fracture interaction, proppant transportation and settlement, casing friction, new government equations of fracture propagation, and fracture roughness. Fully coupled fracture modeling work flows with stress variation, solid transportation, and fluid flow become the mainstream, while model complexity and budget tradeoff remains challenging. Interestingly, fracture modeling has been applied beyond hydrocarbon production. New applications include cutting injection, coal-seam-gas production, and recently evolving enhanced geothermal systems (EGS). Both industrial and academic researchers have made progress on EGS by introducing another dimension of complexity in that thermal effects alter hydraulic fracture modeling behavior. With the advancement of powerful measurement techniques in the past decade, the industry has seen novel ways to calibrate fracture models. Other than microseismicity and pumping-schedule history matching, data collected from downhole tools such as distributed temperature and acoustic sensing and fiber-optic sensors have broader applications and show promising results. By leveraging computational power and machine-learning approaches, scaled-up modeling on the field level energizes the study of well interference, the depletion effect, and frac-hit-damage mechanisms. Recommended additional reading at OnePetro: www.onepetro.org SPE 205896 - Offshore Cuttings Reinjection Well-Performance Diagnostics and Fractured Domain Mapping Using Injection Data Analytics and Hydraulic Fracturing Simulation, Verified Through 4D Seismic and Wireline Logging by Franz Marketz, Sakhalin Energy Investment Company, et al. URTeC 2021-5414 - Modeling of Distributed Strain Sensing and Distributed Acoustic Sensing Incorporating Hydraulic and Natural Fractures Interaction by Kildare George Ramos Gurjao, Texas A&M University, et al. URTeC 2021-5526 - Efficient Modeling of Enhanced Geothermal System With 3D Complex Hydraulic and Natural Fractures by Hongbing Xie, Sim Tech, et al.

Fracture development during disposal of hazardous drilling cuttings by deep underground injection: A review

Drilling fluids with complicated compositions are becoming more common as the oil and gas industry develops. The production of hazardous cuttings is increasing, which not only stifles the oil and gas industry's development but also poses a severe environmental threat. Deep underground re-injection is a cost-effective and efficient method for dealing with hazardous cuttings. Numerous experiments and numerical studies on cuttings re-injection have been conducted in the past thirty years. However, there is still a divergence of views on the fracture development in the process of cuttings re-injection. A comprehensive review of existing studies is necessary to help researchers advance this technology. This paper provides a review of the fundamental studies on fracture behaviors during the deep underground re-injection of drilling cuttings. The limitations of the existing studies are also discussed to inspire new research endeavors.

Case Study: Drill-Cuttings Treatment Alternatives—A Comparative Emissions Assessment

The offshore oil and gas industry has always been cognizant of its impact on the marine environment. The choices that operators make in how they operate, including the disposal of drill cuttings, must address an increasing number of environmental and climate targets in addition to those related to health, safety, and cost. As a typical well will produce approximately 1000 metric tons of oil-based drill cuttings, quantifying greenhouse-gas (GHG) emissions associated with the disposal and treatment of drill cuttings has become an essential step to achieving net-zero ambitions. Since 1991 (1993 for fields in production), strict regulations relating to the discharge of oil-based drill cuttings have been in force under the OSPAR (Oslo/Paris) Convention. Those regulations banned the practice of discharge to sea of untreated oil-based drill cuttings and led to a situation where they were generally shipped to shore for treatment and disposal. In 2020, TWMA engaged DNV, the independent energy expert and assurance provider, to undertake a comparative study between the company’s offshore thermal drill-cuttings treatment solution and conventional alternatives including “skip and ship,” bulk transfer, and cuttings reinjection (CRI) used on the Norwegian Continental Shelf (NCS). It is the first paper to show a direct emissions comparison between offshore processing and alternative methods implemented. The study assessed the carbon dioxide (CO2) footprint and nitrogen dioxide (NOx) emissions for each of the different alternatives. The values were then used to create an interactive emissions calculator that can easily be applied to specific projects to clarify the actual potential for emissions reduction within the drilling waste management process. Background Technological improvements, as well as cost focus on existing solutions, have meant that offshore thermal drill-cuttings treatment has been widely adopted in many offshore basins as one of the safest and most cost-effective approaches. In Norway, which was the subject of the study, adoption of the technology has been slower than in other countries, with onshore thermal treatment of oil-based cuttings applied as the predominant technique, while some fields use offshore slurrification and injection into dedicated disposal wells. However, the cost of drilling new disposal wells and the track record of successful offshore thermal projects in other countries have improved the frame conditions for the use of offshore thermal treatment of cuttings on the NCS. It has also been demonstrated, in an earlier independent comparative study by Carbon Zero (SPE 207519), that the carbon footprint of skip and ship to shore of drill cuttings is 53% higher than that of drill-cuttings treatment at the wellsite (SPE 202639).

Numerical simulation study of oil-based cuttings re-injection induced fractures

Cuttings re-injection is an effective method to solve the accumulation of solid waste such as oil-based cuttings in offshore oil and gas fields, which has the advantages of low cost, high efficiency, and environmental safety. But, the slurry leakage events occur frequently due to the poor understanding of the fracture initiation and extension of cuttings re-injection in existing studies. This paper develops a rock cuttings intermittent re-injection simulator based on the open-source hydraulic fracturing software Pyfrac. The impact of different construction and formation parameters on the propagation of induced fractures was investigated through numerical simulations. The simulation results show that Young’s modulus, Poisson’s ratio and the magnitude of in-situ stress have less influence on the final scope of the fractures. The difference in-situ stress between the re-injection layer and the compartment, the viscosity of the re-injection fluid and the re-injection interval time have significant impacts on the length and height of the fracture. Therefore, in the actual construction process, the liquid viscosity and interval time can be adjusted to obtain the different scopes of induced fractures.

Managing offshore drill cuttings waste for improved sustainability

Drill cuttings are an important waste from drilling operations due to the generated volume and the potential for environmental impacts. Alternatives for treatment and final disposal of these residues are available, with performance differing in multiple aspects, each impacting overall sustainability of existing technologies. Although procedures for comparing sustainability of processes are not new, for end-of-pipe technologies the common approach in the literature is the use of indicators that express the benefit of adding a waste management step. In this scenario, the work presents a methodology for sustainability analysis of solid waste management, adapted to specificities of drill cuttings, illustrated by a case study in the offshore Brazilian pre-salt area. Performance of a given technology is evaluated by integrating environmental, economic, safety and technical aspects in an original multi-criteria analysis. The evaluated waste management technologies are: offshore discharge, onshore disposal, offshore cuttings re-injection and microwave treatment followed by onshore disposal. Process inventories are compiled and support calculation of the proposed Sustainability Degree index for ranking of alternatives, which points to offshore discharge as the most sustainable among the evaluated technologies, followed by Microwave Treatment, Onshore Disposal and Offshore Re-injection. The methodology can indicate opportunities for technical optimization and contribute to the decision-making process on drilling waste management.

Injection in Shale: Experience on the Norwegian Continental Shelf

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170851, “Injection in Shale: Review of 15 Years of Experience on the Norwegian Continental Shelf and Implications for the Stimulation of Unconventional Reservoirs,” by F.J. Santarelli and F. Sanfilippo, Geomec, and R.W. James, H.H. Nielsen, M. Fidan, and G. Aamodt, ConocoPhillips, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed. Waste injection in shale, with matrix permeability in the nanodarcy range and without the presence of any permeable layers, has been performed on the Norwegian Continental Shelf (NCS) for more than 15 years. To avoid leakages to the seafloor using this method, techniques have been developed that allow wells to dispose of several million barrels into individual shale domains, with vertical propagation of the disposal domain less than 1,000 ft above the injection point. Recently, use of frequent 4D interpretations of seismic surveys shot over a permanent sensor array allowed detailed domain mapping and independent dynamic monitoring. Historical Perspective Changes of North Sea regulations in the mid- to late 1990s made the seabed disposal of oily cuttings and other waste from drilling and production impossible without the use of significant topside cleaning systems. Meanwhile, the development of fields required increasingly complex wells, resulting in the almost systematic use of oil-based mud for efficient drilling. This led to a dual challenge for the industry, with an increased amount of waste generated and the difficulty of discharging it. Options were then reviewed between shipping onshore and treatment or reinjection into the subsurface with cuttings-reinjection (CRI) wells (a typical design of a CRI well in the Ekofisk Field region is outlined in the complete paper). Most operators concluded that the CRI option was much safer and more economically favorable than shipping to shore and onshore treating and disposal. A survey of all CRI wells on the NCS noted that 110 had been or were operating, with approximately 30 of them still active at the time of the survey. This confirms the attractiveness of CRI wells as a means of waste disposal, at least as far as the NCS is concerned. Unfortunately, the same survey also revealed that 14 of these 110 wells had suffered from a leakage to the seabed, thus illustrating the risks associated with CRI operations. An outcome of the investigation was the discovery that a vast majority of the leakage-to-seafloor cases occurred in wells where shallow sand bodies were lacking or where their quality was very poor. This justifies the general strategy traditionally adopted by Norwegian operators (i.e., avoiding the upward migration of hydraulic fractures with high-permeability sand bodies); this emphasizes the risks associated with the lack of good-quality “blanket” sands above the injection point.

Nanoemulsion-Enhanced Treatment of Oil-Contaminated Cuttings

This article, written by Dennis Denney, contains highlights of paper SPE 162401, ’Nanoemulsion-Enhanced Treatment of Oil-Contaminated Oil-Based Drill Solids,’ by Wasan Saphanuchart, SPE, Yoong Shang Loke, SPE, and Chun Hwa See, SPE, BCI Chemical Corporation, prepared for the 2012 Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. When oil-based mud is used, the drilled formation solids (cuttings) are regarded as controlled or hazardous waste. As such, they can be disposed of in three ways: decontamination treatment followed by discharge into the sea, injection of the cuttings into the well, or transfer to a controlled hazardous-waste landfill. The lowest environmental effect for solids disposal, especially for offshore operation, is decontamination treatment followed by discharge. However, conventional decontamination technology exhibits limited efficiency in extracting oil from the drill solids. Introduction One function of drilling mud is a washing action to remove cuttings from the wellbore. The mud returns to the surface with entrained cuttings and, typically, flows through shale shakers, desanders, desilters, hydrocyclones, centrifuges, or other devices to separate the cuttings from the mud. Conventional decontamination technology yields an oil content in the treated cuttings of >1% in the dried solids, which does not meet strict environmental regulations in many highly ecologically sensitive countries (e.g., the UK and North Sea countries). Apart from cuttings reinjection, all other treatment methods require land-based waste treatment. Nanoemulsion technology can improve oil-removal efficiency by providing ultralow oil/water interfacial tension (IFT). Heavy- and light-oil extraction from the cuttings surface is enhanced. The cuttings-treatment process proposed in this paper can achieve oil content of <1%. Nanoemulsion Nanoemulsions are clear and thermodynamically stable. In typical nanoemulsions, the droplet size ranges from 10 to 100 nm, which is much smaller than the wavelength of visible light. Hence, nanoemulsions generally are weak scatterers of light, making them transparent. Nanoemulsions can be formulated with a single phase or multiple phases. The IFT between the aqueous and hydrocarbon phases in nanoemulsion systems can be as low as 0.0001 mN/m, compared with an ordinary emulsion or macroemulsion (approximately 0.1 to 30 mN/m). A nanoemulsion might be a dispersion of water in oil or oil in water (in which the second solution is the dispersion medium or solvent). There may also be a bicontinuous structure in which both water and oil are continuous.

Investigation of Drill Cuttings Reinjection: Environmental Management in Iranian Ahwaz Oilfield

This study was to assess the feasibility of drill cuttings reinjection (DCRI) by hydraulic fracturing in two typical wellbore configurations: annulus injection and a dedicated disposal well by tubing and packer completion in one of the oil wells in Ahwaz oilfield. This article shows that the Mishan formation is more appropriate for DCRI in the Ahwaz oilfield. The optimum parameters such as injection rate, batch size, and shut-in time were simulated and used to determine the geometry of hydraulic fractures created during injection and to ensure that the fractures are precisely developed within the targeted injection zone.

Polymer Flooding in Unconsolidated-Sand Formations: Fracturing and Geomechanical Considerations

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121840, ’Polymer Flooding in Unconsolidated-Sand Formations: Fracturing and Geo mechanical Considerations,’ by Mohamad Khodaverdian, SPE, Tibi Sorop, SPE, Sophie Postif, SPE, and Paul Van den Hoek, SPE, Shell E&P, prepared for the 2009 SPE Europec/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. The paper has not been peer reviewed. A study was carried out to determine the geomechanical effects of polymer flooding in an unconsolidated-sand reservoir. The work provided a geomechanical perspective on the generally complex problem of polymer flooding unconsolidated formations containing viscous oil. The work offers insights into critical issues that must be examined in such situations to avoid catastrophic failures and highlights the existing technological gaps in the current predictive capabilities. Introduction Some unconsolidated-sand formations, both onshore and offshore, contain high-viscosity oil and could be considered for polymer flooding to improve recovery. Flooding unconsolidated sand could lead to “fracture” propagation. Although such formations typically have permeability on the order of several darcies, minute quantities of impurities and solids in the injection fluid can plug the sandface over time and lead to fracturing if the injection rate is maintained. Even in the absence of fines and solids in the fluid, the high in-situ oil viscosity and low polymer mobility could instigate fracture propagation if the injection rate is sufficiently large. Polymer flooding was proposed as an option for an offshore field to enhance sweep efficiency and production of viscous 200-cp oil. Aside from the relatively high oil viscosity, the formation characteristics include unconsolidated and highly compressible sand, relatively thick pay zone (gross nominal thickness of 100 m), and relatively small stress contrast between the sand and the caprock (potentially leading to containment loss). The primary goal of the laboratory experiments was to identify the fracturing mechanisms and establish a net propagation pressure in such formations. The findings from the laboratory tests provided empirical input (e.g., equivalent fracture toughness) for numerical simulators. Injectivity Mechanisms Previous R&D. Industry and research institutions have carried out several research projects to address injectivity and hydraulic-fracturing issues in unconsolidated sand. Investigations have focused on several types of field activities, including cuttings reinjection, hydraulic fracturing, frac packing, produced-water reinjection, and water and chemical flooding. Polymer-Injection Tests. In this work, several experiments were conducted in which polymer was injected into oil-saturated sand to investigate the injectivity mechanisms and equivalent fracture toughness under the specific field conditions. Test samples were cubic (45 cm) sand blocks.

A Novel Hydraulic Fracturing Model Fully Coupled With Geomechanics and Reservoir Simulation

Summary Unconventional fracturing techniques, such as high-rate waterfracs, waterflooding, or steam stimulation, produced water and cuttings reinjection, CO2 sequestration, and coalbed methane stimulation, are difficult to model because of strong interactions among the fracturing process, geomechanical changes in the porous media, and reservoir fluid flow. The resulting strong poroelastic/thermoelastic effects, permeability and porosity changes, and possible rock failure make current conventional fracturing models inadequate in such circumstances. Therefore, it is necessary to develop new models that include all of these mechanisms and that are capable of conducting integrated data analysis. This paper presents a new fracturing model with all of these mechanisms included. The model fully couples fracture mechanics with reservoir and geomechanics simulation. This methodology allows us to model fracture initiation and propagation, post-frac multiphase cleanup in the reservoir and fracture and pre-frac and post-frac well performance in a changing stress and pressure environment, all within the same system. The model couples a 3D finite element geomechanics model with a conventional 3D finite difference reservoir flow simulator. The geomechanics module implicitly models fracture propagation via displacements on the fracture face. The flow and geomechanics/fracturing are coupled in an iterative manner that is equivalent to full coupling of geomechanical and reservoir flow modeling. The 3D (planar) fracture geometry and the pressures in it are the common dynamic boundary conditions for the flow and stress modules. The new iterative process yields smooth fracture propagation, and the model has been tested on classical fracturing problems. A field example demonstrates the validity and advantages of the approach. To illustrate the model capabilities, we model a waterfrac stimulation performed in Bossier tight-gas sands. The model results show that the model is capable of matching complex injection history and calibrating the stress-dependency of formation permeability.

Environmentally Safe Waste Disposal: Integration of Cuttings Collection, Transport, and Reinjection

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108912, "Environmentally Safe Waste Disposal: The Integration of Cuttings Collection, Transport, and Reinjection," by A. Alba, SPE, F. Fragachan, SPE, A. Ovalle, SPE, and T. Shokanov, SPE, M-I Swaco, prepared for the 2007 SPE International Oil Conference and Exhibition in Mexico, Veracruz, Mexico, 27-30 June. The paper has not been peer reviewed. Many regulatory agencies are demanding zero-discharge policies, requiring all generated wastes to be disposed of in a responsible manner. This requires adequate management of wastes generated during drilling operations, including cuttings, excess drilling fluid, contaminated rainwater, produced water, scale, produced sand, and production and cleanup waste. Old practices involve temporary box storage and hauling waste products to a final disposal site. Often, these sites are several kilometers away from the generation source, creating not only liabilities for the operating company but also environmental risks. Introduction The three main drivers for selection of a cuttings-collection and -transport system and reinjection package are regulations, logistics, and cost. Depending on the country, region, or marine area, the existing regulations may or may not allow discharge or transportation of waste. In some areas where regulations are less stringent, transportation of generated waste to satellite disposal sites (on land or offshore) is allowed. In highly sensitive areas where zero-discharge policies are enforced strictly, all generated waste must be stored, treated, and disposed of in situ. Because of such limitations, drilling operations often are limited by collection capacity and ability of the cuttings-reinjection (CRI) system to inject all waste concurrently. A new approach is to decouple the injection process from the drilling operation, providing a totally independent cost-effective process. For logistics, the main limitations are determined by rig configuration, space availability, material type, distance of material transportation, and safety, which ultimately translate into costs. Each operation should be analyzed individually to determine logistics, cost, and compliance with local regulations, so proper collection, transport, and reinjection packages are tailored to fit the specific needs of the project. CRI In general, CRI is a process wherein solids (cuttings) and liquids (waste fluids) are gathered and conveyed to a series of components that classify, degrade, mix, and condition them into a stable and pumpable slurry. This slurry then is injected into a subsurface formation that is receptive and permanently isolated at a safe depth beneath caprock to prevent migration to the surface.

Increased Assurance of Drill Cuttings Reinjection: Challenges, Recent Advances, and Case Studies

Summary The handling of drill cuttings and other wastes generated by drilling operations is both an environmental and economic issue. With ever-tightening environmental regulations and the green operation initiatives of operators, drill cuttings reinjection (CRI) into subsurface geology is often the preferred option, allowing operators to achieve zero discharge because oily cuttings are returned to their place of origin. When the technology was introduced about a decade ago, injection into a single well had a maximum slurry volume of approximately 30,000 bbl. Now, particularly in very large projects, several million barrels of slurry can be injected into a single well. This represents more than 1,000 times the volume of a typical hydraulic fracturing job, or more than 100 times that of earlier cuttings reinjections. In some cases, the success of the CRI operation is critical, either because there are no backup options or because the economic and environmental impacts are too significant. This paper describes the challenges faced in CRI projects, along with recent advances and experience gained in tackling these challenges through modeling, cuttings slurry and operational procedure design, monitoring, and verification. For example, much progress has been made recently in slurry rheology design and operational procedure selection such as suspension and displacement to avoid loss of injectivity and to maximize disposal capacity and minimize health, safety, and environment (HSE) issues. The authors will also present a risk-based approach that integrates deterministic software and tools, available data, knowledge, and experience, for modeling of geological and operational uncertainties and potential risks to increase quality assurance. Case examples will be presented to illustrate the value of this integrated approach. Best-practice guidelines and recommendations will be provided for data collection, design and engineering, operation, and monitoring.

A Risk-Based Approach to Waste-Containment Assurance

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98202, "Formation Damage and Its Impact on Cuttings-Injection-Well Performance: A Risk-Based Approach on Waste- Containment Assurance," by Q. Guo, SPE, and T. Geehan, SPE, M-I Swaco, and K.W. Ullyott, SPE, EnCana Corp., prepared for the 2006 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 15–17 February. With ever-tightening environmental regulations, drilling-waste disposal by downhole hydraulic fracturing is often the preferred waste-management option to achieve zero discharge. However, formation damage caused by solids-laden-slurry injection can cause uncertainties in injection-well performance and waste-containment assurance. Complicating the problems are the many formation-damage mechanisms that are difficult to model. A probabilistic approach based on Monte Carlo simulations has been developed to model formation damage and its contribution to injection-well performance and waste-containment assurance. Introduction The principal waste product of the drilling process is oil-contaminated drill cuttings. One of the preferred waste-management options is downhole injection into a deep geological formation by use of hydraulic fracturing. This technology is known as cuttings reinjection (CRI). A drill-cuttings-injection operation involves the collection of solid waste from solids-control equipment (i.e., a shale shaker) on the rig and its transportation to a slurrification unit, where the cuttings are ground into small particles and combined with water to make a slurry. The slurry then is transferred to a slurry holding tank for final slurry-rheology conditioning. The conditioned slurry is pumped through a casing annulus or a tubular into subsurface fractures created by injecting the slurry under high pressure into the disposal formation. The waste slurry often is injected intermittently in batches into the disposal horizon. Each batch injection may last from a few hours to several days or even longer, depending on the batch volume and injection rate. The waste-storage mechanism is similar to hydraulic fracturing in reservoir stimulation and circulation loss in drilling. However, because the created fractures from cuttings-slurry injection can be very large, because of the large volume of slurry injected, the extent of the fractures must be understood to ensure that the injected material will not migrate into areas where it could create problems, such as contamination of underground potable-water zones. Containment assurance often is provided by numerical simulations. The extent of the fractures created by cuttings-slurry injections must be predicted with confidence. However, the simulation results are only as good as the quality of the data entered into the simulators. Uncertainties are present in any projects involving subsurface geology. Prediction of fracture length and overall profile, which will contain the injected waste, and also the disposal capacity, depends strongly on how many fractures are generated from intermittent slurry injections. When and where secondary fractures are generated may depend on factors such as initial in-situ stress magnitude and orientations, local stress change from cuttings-injection operations, and many other geological conditions. While uncertainties will exist, these may be evaluated with increased confidence by use of information obtained during the actual CRI operations. Because it is never possible to have total certainty about all the geological and operational information, a probabilistic approach to waste-containment assurance and risk assessment of CRI operations is appropriate.

Overview: Drilling and Cementing Technology (February 2007)

2006 confirmed foreseen changes. The demand for oil was near the offer or production capacity and the rather stable high oil prices induced new drilling programs. The result was a drilling-rig market with use near 100% and new rig construction for the offshore fleet nearing 100 rigs. The wake-up was rather sudden. If current programs use mostly conventional drilling technology while constant technology evolution improves productivity, new prospects soon will require new drilling technology. Papers highlighted here and listed for additional reading describe recent technology advances. R&D programs in 2005 and 2006 anticipated the need for new technology.In the ultradeep offshore, water depth more than 10,000 ft, conventional riser architecture has reached its limit; the hyperstatic riser is one solution.In deep prospects and extended-reach wells that require multiple intermedi-ate casings, monobore architecture renders these projects feasible.In deep buried reservoirs, the effects of high temperature require careful review of the cement formulation.In some mature or shallow unconsolidated prospects with low fracture gradients, the use of ultralight cements may be required.For production from acidic environments, long-term cement-sheave durability must be studied. Noticeable efforts have been made to improve more-conventional drilling.Understanding drillstring behavior and taking into account contact forces related to string bending will improve trajectory prediction, and its monitoring will certainly increase the overall rate of penetration.Various methods of cuttings disposal exist, and the understanding of cuttings reinjection is improving.The reliability of cement-bond logs has improved with respect to zone isolation, especially when communication tests are impractical or cost-prohibitive. Drilling and Cementing Technology additional reading available at the SPE eLibrary: www.spe.org SPE 99105 "Durability of Oilwell Cement Formulations Aged in H2S-Containing Fluids" by E. Lecolier, SPE, Inst. Français du Pétrole, et al. SPE 98124 "Ultralightweight Cementing Technology Sets World Record for Liner Cementing With a 5.4-lbm/gal Slurry Density" by D. Kulakofsky, SPE, Halliburton, et al. SPE 99005 "First Hyperstatic Riser Joint Field Tested for Deep Offshore Drilling" by Y. Poirette, SPE, Inst. Français du Petróle, et al. SPE 98965 "Advancements in 3D Drillstring Mechanics: From the Bit to the Topdrive" by S. Menand, SPE, École des Mines de Paris, et al.

A Simple and Accurate Description of Nonlinear Fluid Leakoff in High-Permeability Fracturing

Summary Fluid leakoff in hydraulic fracturing is conventionally described using the well-known linear (Carter) model. Although this works well in low-permeability formations, the linear leakoff assumption may lead to sometimes significant overestimation of fracture dimensions in medium- to high-permeability formations. At present, no methodology is available that allows an easy estimation of the impact of nonlinear fluid leakoff on fracture dimensions and on pressure decline (minifracture) analysis. This paper aims to resolve that deficiency. An exact numerical solution is presented to the fully transient elliptical fluid-flow equation around a propagating hydraulic fracture for arbitrary pump rate(s). In addition, a simple analytical formula for elliptical leakoff rate is presented that is shown to yield an excellent approximation of the numerical results, both during fracture growth and after shut-in. This formula can be easily incorporated into any existing hydraulic fracture model, and it is applicable over the entire range of fluid leakoff rates (i.e., from low-permeability fracture stimulation on one hand to high-permeability waterflood fracturing on the other). The above result is applied to a variety of hydraulic fracturing field examples to explore the limits of the linear (Carter) leakoff assumption, both in pressure-decline analysis of minifractures and in fracture design. It is shown that in frac-packing and high-perm cuttings reinjection (CRI), the linear leakoff assumption may lead up to a tenfold overestimation of fracture dimensions. Conversely, incorporating nonlinear leakoff in the minifracture interpretation of high-permeability fractures will yield larger minifracture radii and lower total leakoff coefficients. This will result in more aggressive pump schedules.

Drill Cuttings Reinjection

This article is a synopsis of paper SPE 72308, "Design Considerations in Drill Cuttings Reinjection Through Downhole Fracturing," by Ahmed S. Abou-Sayed, SPE, and Quanxin Guo, SPE, Advantek Intl., originally presented at the 2001 IADC/SPE Middle East Drilling Technology, Bahrain, 22-24 October.