Synthetic-based Drilling Fluids Research Articles

Polymer Replacement for Organophilic Clay Benefits Mineral-Oil-Based Drilling Fluids

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191776, “Successful Replacement of Conventional Organophilic Clay With Novel Polymer as Viscosifier and Filtration-Control Agent in Mineral-Oil-Based Drilling Fluids,” by Jing Zhou, SPE, Jairo Cortes, SPE, and Hisham Nasr-El-Din, SPE, Texas A&M University, prepared for the 2018 SPE Liquids-Rich Basins Conference—North America, Midland, Texas, USA, 5–6 September. The paper has not been peer reviewed. Organophilic clays mixed in oil-based drilling fluids (OBDFs) do not exhibit the same viscosity or suspension characteristics as they do in water-based drilling fluids because electrical interaction between particles is minimal, creating difficulty in building viscosity and gel strength under high-pressure and high-temperature (HP/HT) conditions. To address that problem, a new mineral-oil-based drilling fluid (MOBDF) was created by replacing the conventional organophilic clay with a novel polymer. Introduction Organophilic clays are widely used as primary viscosifiers for OBDFs and synthetic-based drilling fluids. These chemicals are prone to stratification in certain conditions, slow chemical-reaction times, high pressure spikes, and high equivalent circulating densities (ECDs). These mud systems also have temperature limitations. At high temperatures, thermal thinning and thermal degradation of their organophilic colloids permanently destroy their viscosification capabilities. At low temperatures, excessive and rapidly increasing viscosity is experienced. A need, therefore, exists for a fluid that produces higher gel strengths initially and maintains a relatively flat response to temperature throughout the complete temperature cycle of a drilling operation. Organophilic clays mixed in OBDFs do not exhibit the same viscosity or suspension characteristics as they do in water-based drilling fluids because electrical interaction between particles is minimal, creating difficulty in building viscosity and gel strength under HP/HT conditions. By switching from a standard OBDF containing organophilic-clay additives to a clay-free OBDF, the drilling operation will benefit from a drilling fluid capable of performing under the desired conditions planned, an overall reduction in logistics, a reduction in volume of fluid and material needed, higher rates of penetration because of lower ECDs, and the formation of a thin nondamaging filter cake that would eliminate the need for costly and time-consuming cleanup treatments. This paper studies the feasibility of developing an organophilic-clay-free drilling fluid capable of performing similarly to an already-tested drilling fluid containing organophilic-clay additives. Experimental Studies Two MOBDF formulas were used for the experiments. The first, MOBDF A, was prepared with a formula containing organophilic-clay additives. The second, a clay-free drilling fluid, MOBDF B, was prepared with a formula containing the replacement polymer viscosifier and filtration-control agent. Calcium carbonate was chosen as the weighting material for the two MOBDFs used for the analysis. High-permeability Indiana limestone cores with a thickness of 0.25 in. and a diameter of 2.5 in. were used to perform the filter-cake-formation and filtration analysis. Berea sandstone cores with a thickness of 6 in. and a diameter of 2.5 in. were used to perform the rock-wettability and emulsion-breakdown analysis. Both MOBDFs were heated to 150°F for 16 hours under hot rolling, and no phase separation was observed.

Thermodynamic Behavior of Olefin/Methane Mixtures Applied to Synthetic-Drilling-Fluid Well Control

Summary The presalt hydrocarbon discoveries in Brazilian deep water have been a challenging environment for drilling operations as a result of the technical demands and restrictions and the environmental regulations driving scientific and technological development. In this drilling context, an accurate estimation of the downhole pressure is mandatory to avoid drilling problems such as kicks, lost circulation, and wellbore instability. When considering kick prevention and control, understanding of the mixture behavior (drilling fluid and formation gas) is essential to improve the estimation of the downhole pressure, which would support efficient, safe, and economic drilling operations. The widespread application of synthetic-based drilling fluids in the Brazilian presalt polygon is justified by the technical performance offered by this kind of drilling fluid, such as reduced drilling time compared with water-based drilling fluids, increased lubricity in directional and horizontal wells, and shale-swelling inhibition. In addition, this is an environmentally friendly alternative to oil-based drilling fluids. However, those fluids are more sensitive to pressure and temperature variations than water-based drilling fluids. To obtain a better understanding of the behavior of one specific kind of synthetic-based drilling fluid, the olefin experimental research was conducted and the results and findings are presented in this technical article. The work involved pressure/volume/temperature (PVT) measurements for olefin/methane mixtures to investigate the effect of pressure, temperature, and mixture composition on thermodynamic properties such as density, formation volume factor (FVF), gas-solubility ratio, and saturation pressure. Those properties are important for knowledge of the mixture volumetric behavior at downhole conditions, especially when gas enters the wellbore. The experiments were conducted at isothermal conditions, and a gas-enrichment experimental procedure was applied. The temperature range was from 25 to 80°C (77 to 176°F), the gas molar fraction (GMF) ranged from 30 to 50%, and pressure was up to 69 MPa (10,000 psi). In addition, the measured data were compared with an existing database (Silva et al. 2004; Atolini 2008) for methane/n-paraffin mixtures, as well as for methane/ester mixtures (Kim et al. 2015). Pit-gain analyses were also performed according to the procedure of Monteiro et al. (2010), and a comparison of the results with other base fluids showed interesting findings.

Novel Synthetic-Based Drilling Fluid through Enzymatic Interesterification of Canola Oil

Over the years, the oil industries have avoided aromatic, naphthenic, and paraffinic oils as drilling mud base fluids principally because of their detrimental environmental issues on pelagic and benthic marine ecosystems as a result of their toxicity and nonbiodegradability coupled with the possible deterioration of the oil itself and the rubber parts of the drilling equipment because the aromatic hydrocarbons present in the oil have a tendency to dissolve/damage elastomers present in rubber. Hence, possible insights into how to chemically and/or physically produce synthetic base drilling fluids whose cuttings are nontoxic, readily biodegradable, environmentally friendly, and of nonpetroleum source become imperative. In this study, enzymatic interesterification of canola oil was done with ethanol by using enzyme lipase as catalyst under optimum conditions of temperature and pressure and the physicochemical properties of the produced ester were evaluated and compared with that of diesel and a synthetic hydrocarbon base fluid (SHBF). Results show that the specific gravity, kinematic viscosity, dynamic viscosity, and surface tension of canola oil were reduced by 5.50%, 94.74%, 95.03%, and 9.38%, respectively, upon enzymatic interesterification to conform to standard requirements. Similarly, increased |mud ability to pump fluids and possibility of cold temperature environment can be achieved with the reduction in pour point and cloud point, respectively, of the produced canola oil ester. Finally, the produced ester showed no aromatic content as confirmed from its FTIR analysis which indicates its nontoxicity, biodegradability, and environmental friendliness.

Nonionic polyol esters as thinner and lubricity enhancer for synthetic-based drilling fluids

This study evaluates the performance of polyol esters as thinners and lubricity enhancers in invert emulsion synthetic-based drilling mud (SBM). Three types of polyol esters, namely pentaerythritol ester (PEE), trimethylolpropane ester (TMPE), and neopentyl glycol ester (NPGE), were prepared at various concentrations of 1, 2, and 3% (v/v) in SBM. The results showed that polyol esters reduced the rheological properties of the drilling mud, such as yield point and gel strength, after the hot rolling test at 135 °C. The rheology data was fitted to the Herschel-Bulkley model to describe the shear thinning behaviour of drilling mud. The model parameters showed that the polyol ester resulted in lower yield stress of SBM, which indicated lower forces are needed to initiate a fluid to move. Their relative effectiveness as a lubricity enhancer was evaluated by measuring the coefficient of friction (COF), wear scar diameter, and scar topography. It was found that polyol esters reduced the COF of SBM by 22% at a concentration of 1% (v/v). PEE provided the best friction reduction and anti-wear performance due to a higher number of the ester group and molecular weight, in comparison with NPGE and TMPE. The lubricity improvement for SBM is recently required by off-shore regulations.

Performance Evaluation of Synthetic-Based Drilling Fluid with Flat Rheology

In offshore deepwater drilling, because of the low temperature aroud seafloor, the conventional synthetic-based drilling fluid becomes very thick, resulting in severe loss of drilling fluid during drilling through the deepwater formations with a narrow safe-density window. Therefore, it is important to improve the rheological properties of drilling fluid at deepwater drilling conditions. In this work, by investigating the effects of the key components including the base oil, emulsifier, wetting agent and rheology modifier on the rheological properties of synthetic-based drilling fluid at 4°C to 65°C, the optimal additives were selected, and a synthetic-based drilling fluid with flat-rheology characteristics was developed. It was found that the gas-to-liquid oil had low viscosity at a low temperature, and was suitable for preparing deepwater drilling fluids. The evaluation experiments show that at 4°C to 65°C, the drilling fluid could maintain stable yield point, 10-min Gel and 6 r/min reading value at a density of 0.9-1.5 g/cm³ even after high temperature aging, while the rheological properties of the conventional synthetic-based drilling fluid were significantly influence by the low temperature. Moreover, it showed excellent performance in filtration reduction and shale inhibition, and could maintain good properties even being contaminated by seawater. Therefore, its stable rheological properties at the deepwater drilling temperature range can effectively control the equivalent circulating density, thus reducing the risk of drilling fluid loss during deepwater drilling.

Quemada model approach to oil or synthetic oil based drilling fluids rheological modelling

Understanding and modelling the deviations from Newtonian behavior of synthetic-based drilling fluids (SBFs) is essential to design optimal flow systems and efficient cuttings transport. This research develops a better insight into synthetic fluid rheology based on the theory of internal structural units (SUs) suspensions. Although different studies have been proposed to characterize SBF rheology, yield stress and time dependency proved difficult to determine. This study explains how most difficulties disappear when taking thixotropy into account. The behavior of structural units and effective volume fractions as a function of shear rate, has been analyzed by Qemada (1998) to develop a rheological model for particles suspension. This rheological model has been modified to describe the behavior of SBFs. For validation purposes, an industrial SBF used for drilling in a shale reservoir is analyzed. A novel experimental procedure is proposed that makes extensive use of rotational rheometers to estimate the parameters of the model. Various combinations of temperatures and resting times have been tested to develop semi-empirical correlations for the model parameters. In addition, a practical use of the model is demonstrated by accurately estimating the settling of retrieved shale cuttings through the analyzed synthetic fluid. The experimental protocol represents a design tool for onshore and offshore drilling operations that involve SBFs, with potential improvements on optimization of flow systems and cuttings transport efficiency.

Advanced distributed fiber optic sensors for monitoring real-time cementing operations and long term zonal isolation

This paper presents an advanced fiber optic distributed temperature and strain sensing (DTSS) system designed for real-time in-situ monitoring of cement presence and integrity in the annuli of an oil and gas well. The DTSS system is used to monitor cement quality and zonal isolation by application of hybrid Brillouin and Rayleigh technology. This sophisticated technology allows for separate strain and temperature measurements using a single optical fiber.The DTSS system enables monitoring of the exothermic cement hydration reactions after a cement slurry is displaced into an annular space and allowed to set. In the laboratory, temperature and strain profiles were measured using the DTSS system at various external temperatures to quantify the effect of heat release during cement hydration. The temperature measurements showed excellent agreement with those obtained from thermocouples embedded in the same cement samples for comparison. Contamination of cement due to incomplete displacement of drilling fluid by cement slurry was also considered in the experiments. Contamination with synthetic-based drilling fluid was found to decrease the amount of heat generated during the cement hydration reactions. The degree of cement hydration and the presence of cement in the annular space - or lack thereof - can therefore be quantified. It is shown that the temperature profiles measured using the DTSS system can be used to detect both the top of cement (TOC) as well as annular sections that are either left uncemented or contaminated with drilling fluid.In addition to monitoring cement hydration, specially designed fiber optic sensing cables were developed to detect the presence and migration of hydrocarbons in cemented annuli, which may occur either because the cement is absent or compromised by cracking/fracturing. The fiber optic cables were modified with hydrocarbon-sensitive coatings generating a swelling effect when exposed to hydrocarbons. Such swelling effect could be measured and quantified using an induced strain on the fiber optic cable, which is monitored and recorded by the DTSS system. The modified cable was also evaluated for its response to various well construction fluids (such as synthetic based drilling fluid, spacers etc.).The ability to monitor cement hydration and hydrocarbon presence behind casing using cement-embedded fiber optic sensors that provide real-time, continuous responses without the need for wellbore re-entry presents a powerful new tool to assess and verify the quality of zonal isolation over the entire lifecycle of the well.

Experimental study and molecular simulation of gas dissolution and diffusion behavior in drilling fluid

An appropriate knowledge of annulus multiphase flow behavior is critical to ensure a safe well control operation in the event of a gas kick scenario during well drilling activities. However, owing to formation gas solubility in drilling fluids, the dynamic distribution of dissolved gas and free gas in the annulus will induce a complex annulus flow pattern, which provokes potential safety risks in the operation. To determine the magnitude of this effect, some fundamental works have been carried out in this paper. Experiments to measure methane solubility in brine, white oil and poly-alpha-olefin, which represent water-based, oil-based and synthetic-based drilling fluids, respectively, were performed under different temperature and pressure conditions. The attained solubility data are helpful in understanding the distribution of annulus dissolved gas and free gas, they can provide some references for evaluating the risks associated with safety well control in a gas kick scenario. Molecular dynamics simulations were also performed to study the mechanism of methane dissolution and diffusion in drilling fluids at microscopic level. It was observed that the “capacity”, “power” and “path” of methane molecules in the solution will determine the extent of its solubility in the drilling fluid. According to the results, the “capacity”, “power” and “path” for methane molecules to dissolve in white oil and poly-alpha-olefin is greater than in brine, suggesting the same dissolution features as the experimental results. Therefore, the molecular simulation can be an effective approach to predict the dissolution performance of different gas/drilling fluid systems with these evaluation criteria. In addition, with a better recognition of the gas dissolution process, the simulation results also provide support for further research on annulus transient multiphase flow behavior.

The Effect of Borehole Pressure on the Drilling Process in Salt

Summary Wells penetrate long intervals of salt to access hydrocarbon reservoirs in many locations. High mud weights are frequently used to stabilize the wellbore while drilling through salt formations. High borehole pressures reduce rates of penetration (ROPs) in many sedimentary rocks. This effect is significant and contributes greatly to the low ROPs and high costs associated with deep drilling. This paper presents the results of an integrated laboratory study of the effect of borehole pressure on the drilling process in salt. The study included full-scale laboratory-drilling tests, visual single-point-cutter tests, and triaxial-compression tests. The drilling tests were performed by use of a polycrystalline-diamond-compact (PDC) bit and a synthetic-based drilling fluid typical of field practice. The visual single-point-cutter tests used a clear drilling fluid, enabling observation and video recording of the salt-cutting process at elevated borehole pressures along with simultaneous measurement of the cutting forces. The effect of borehole pressure on drilling salt is seen to be small; increasing borehole pressure does not reduce ROPs in salt as much as it does in many other sedimentary rocks. In contrast to other sedimentary rocks, salt deforms plastically to relatively large strains in compression without loss of mechanical integrity, even at low confining pressures. In addition, the shear stress to achieve a given strain does not increase greatly with confining pressure. Rock-cutting forces in the single-cutter tests increased only moderately as borehole pressure was increased from 300 to 6,000 psi. Full-scale bit-penetration rates also decreased by relatively small amounts over the borehole-pressure range investigated (1,000–6,000 psi). Mechanical-specific-energy (MSE) levels showed corresponding small increases. These levels, however, were consistently much higher than the compressive stresses required to make even large strains at a confining pressure equivalent to the borehole pressure. Observations of the deformation and cutting processes in salt combined with results of finite-element analyses of rock and metal cutting explain the low sensitivity to borehole pressure of halite-penetration rates and its relatively high specific energy. This study fills a gap in industry knowledge of pressure effects in drilling and sheds light on the processes involved in drilling rock salt. The key practical conclusions are that ROPs and MSE in salt are not greatly influenced by borehole pressure. Consequently, if a high borehole pressure is required to stabilize the wellbore through a salt formation, there is little penetration-rate penalty to be paid, except perhaps if increasing the mud weight involves significant changes to the drilling-fluid properties other than its density. The comparison of results from visual single-point-cutter and full-scale bit tests suggests, unsurprisingly, that reducing bit-cutter density and modifying drilling-fluid properties may both offer routes to increase ROPs in salt. The current study does not, however, investigate directly the effect of fluid properties on the drilling process in salt.

The novel approach for the enhancement of rheological properties of water-based drilling fluids by using multi-walled carbon nanotube, nanosilica and glass beads

Abstract Nano and micron materials are investigated in water-based drilling fluid (WBDF) to improve its rheological behaviour. Due to the environmental and certain operational concerns, the use of oil-based drilling fluid (OBDF) and synthetic based drilling fluid (SBDF) is restricted that caused the industry seeking for new ways to enhance rheological properties of WBDF. This study was based on investigating the applicability of multi-walled carbon nanotube (MWCNT), nanosilica and glass beads (GBs) as primary additives for enhancing the filtrate volume, lubricity and other rheological properties of WBDF. This study focused on the effect of different concentrations such as 0.001 ppb, 0.002 ppb, 0.01 ppb, 0.02 ppb, 0.1 ppb, and 0.2 ppb of each MWCNT and nanosilica over the rheological performance of WBDF. Effect of GBs of different sizes such as (90–150 μm) and (250–425 μm) was investigated at different concentrations of 2 ppb, 4 ppb, 6 ppb, 8 ppb, 10 ppb, and 12 ppb over rheological performance of WBDF. Results revealed that coefficient of friction (CoF) for drilling fluid without nanoparticles and GBs was 0.238. 0.01 ppb of MWCNT and nanosilica provided 44% and 38% CoF reduction. 4 ppb of GBs (90–150 μm) provided 28% CoF reduction. MWCNT showed 4.5 ml of filtrate volume and 2/32 inch of mud cake thickness. Thus, MWCNT can be a better choice as a drilling fluids additive for WBDF.

Experimental investigation of new additive to optimize the properties of synthetic-based drilling fluid

This paper focus on the design, development and testing two type of synthetic based drilling fluid include of amine-treated Quebracho agent and Polymeric Fluid Loss agent. Amine-treated Quebracho agent is compatible with other chemical additives in Synthetic-Based Fluids and it shows high-temperature stability, low fluid losses and good Rheological properties. Traditionally invert emulsion drilling fluids have been used to optimize drilling performance primarily due to the high level of wellbore stability and high penetration rates shown while using these fluids. Invert emulsion fluids require various additives such as emulsifiers, fluid-los-control (FLC) agents, viscosifier etc. The paper includes the laboratory evaluation for high temperature application of two agents in invert emulsion drilling fluids.

Improved Coefficient of Friction Using Different Types of Lubricants in Drilling Operation

The key performance of any drilling operation depends heavily on the choice of drilling fluid used as well as how good it can overcome the drill pipe friction. It is essential that the drilling fluid be able to reduce bit wear, torque and drag. Drilling with oil-based drilling fluid offer less torque and drag. However, water based drilling fluid are cheaper and environmental friendly compared to oil-based and synthetic-based drilling fluids. Lubricants are added to drilling fluid to produce a thin film of liquid that separates the solid surfaces in contact to reduce the friction to an acceptable range. This study focused on the performance evaluation of two different commercial lubricants, which are EBL and EME salt to improve the lubricity of water based drilling fluid. The performances of lubricants were evaluated by ranging the concentrations from 1%, 2% and 3%. Fann Lubricity Tester is used to test the lubricity of these lubricants. The results reveal that the coefficients of friction for all lubricants were reduced after reaching the optimum concentration at the range of 1 - 2%. Some improvements were observed on the rheological properties such as plastic viscosity, yield point and gel strength when the lubricants were added to the drilling fluid. The values satisfy the requirement accepted by the industry. This study also showed that the applicants of EBL lubricant is better than EME salt in term of reducing the coefficient of friction in drilling fluid.

PVT behavior of methane and ester-based drilling emulsions

Abstract Well construction is especially complex in deep and ultra-deep water, where large Brazilian oil and gas reserves are located, demanding the use of synthetic-based drilling fluids, which have adequate characteristics such as lubricity, shale stabilization and low toxicity. Hydrocarbon gas kick will dissolve to some extent in any drilling fluid, but this effect can generally be ignored with a water-based drilling fluid. However, an operator working with synthetic-based drilling fluid must have training in gas solubility to avoid a blowout situation. Methane is the main component of natural gas, while ester can be used in the formulation of synthetic drilling fluids. To study phase equilibrium of these gas–liquid mixtures, at high pressures and high temperatures, found in bottom-hole conditions, specific, work and time intensive experimental tests were performed. The objective of this work is to present the experimental PVT data obtained from methane and ester emulsion mixtures. The fluid was loaded into a PVT cell and tests were carried out at desired conditions. Gas enrichment procedure was devised to cover temperature, pressure and methane concentration range with a long-term, single liquid amount test. Thermodynamic properties such as bubble pressure, solubility, density and formation volume factor of these mixtures were calculated up to 103 MPa and 130 °C, similar to bottom-hole conditions. A model based on the Peng–Robinson equation of state was used to predict the bubble point of the mixture.

Performance of fiber-containing synthetic-based sweep fluids

Abstract Cuttings transport from the bit to the surface in horizontal or highly inclined wells is a critical component of overall drilling performance. The associated increase in bottomhole pressure and equivalent circulating density due to increased cuttings concentration and formation of cuttings bed in the wellbore can exceed the limits of the marginal operating pressure window that often exists in deepwater drilling. Fiber-containing sweeps, or “fiber sweeps”, have been shown to be effective in cleaning highly inclined wells by eliminating cuttings beds, thereby reducing the friction pressure loss. Incorporating fiber in a drilling sweep enhances its hole-cleaning performance and minimizes friction loss contributions from cuttings beds without significantly impacting flow properties of the fluid. This article presents the results of an experimental study conducted on the wellbore cleaning efficiency of fiber sweeps. Wellbore cleaning experiments were conducted with sweeps of synthetic-based drilling fluid (SBM) of density 1.27 g/mL treated with a monofilament synthetic fiber of density 0.9 g/mL, length 10 mm and diameter 100 μm. Fiber concentration was varied up to 0.06% w/w (0.54 g of fiber/L of fluid). The flow loop contained an annular test section and was fitted with a pipe viscometer. Cuttings bed heights in the flow loop annulus were measured at flow rates up to 300 L/min and pipe rotation speeds up to 50 rpm with the annulus configured horizontally (90°) and inclined at 72°. The results indicated that in the inclined configuration, addition of fiber to hole-cleaning sweeps substantially improves cuttings removal, but only when the pipe is rotated. When the annulus is horizontal or the pipe is not rotated, addition of fiber has only a small effect on cuttings bed removal.

Ether-Based Muds Show Promise for Replacing Some Oil-Based Muds

Two different polyethers were evaluated for their potential use in drilling fluids as a base fluid for synthetic ether-based mud, which is one type of synthetic-based drilling fluid that are used when drilling for oil and gas by a rotary method and they have several technological and environmental advantages over oil-based mud. Polyglycerol or polytriethanolamine, which derive from the condensation reaction of glycerol or triethanolamine was used as a base fluid in the formulation of ether-based mud in comparison with oil based mud. The evaluation includes the study of rheology, filtration properties, electrical stability, and thermal stability for oil-based mud and synthetic ether-based mud, which are formulated of polyglycerol or polytriethanolamine. The result show that the tested synthetic ether-based mud are more viscous at low temperature, thin more with increasing temperature, and have high thermal stability than oil-based mud. Biodegradation of the mud formulated with polyglycerol or polytriethanolamine was also studied.

Technology Focus: Health, Safety, Environment, and Social Responsibility (August 2013)

Technology Focus If there is a field where human thought is necessarily joined to action, it is health, safety, security, environment, and social responsibility (HSSE-SR). It is critical to develop the technology, the skills, and the culture needed to achieve no harm to people, no damage to the environment or the assets, and an overall benefit to society, in particular to the local people—in other words, to find and produce hydrocarbons in a safe manner, preserving the ecosystems and the environment at large. Everyone—not only the HSSE-SR professionals—must realize that they have a role to play to achieve these goals. Prevent and anticipate, but also prepare for the unthinkable: It all relates to what is our most precious treasure, our physical and mental integrity, today and tomorrow. The link with health is immediate, and it is why there are close connections with what the pharmaceutical industry does, or should do: find new products that meet the needs of the people, identify the hazards, and check by clinical assays—all measures to ensure that the technical solutions that are implemented have a net benefit to society and will not cause detrimental side effects in the long term. We are all concerned, whatever our position in the company is, whether we work for an operator or for a service company, whether we work in an office or on an installation, as an HSSE-SR professional or in another capacity. In addition, when an incident occurs (blowout, air pollution, or social problem), wherever it happens, it is at the whole industry that the finger of shame is pointed. One may think that HSSE-SR can provide a competitive advantage to companies. And that is probably true in a few cases. But, in most cases, it is the whole industry that benefits from progress and the whole industry that suffers from highly publicized incidents. What is the relation with JPT? Well, SPE is committed to disseminate best practices by sharing case studies, and—especially in HSSE-SR—to disseminate best thoughts on how to address the complex issues raised. The following pages will hope-fully demonstrate that progress is being made and, more importantly and a key criterion for paper selection, that progress made somewhere can be widespread (i.e., reused in another location by other companies). Let me remind you that additional stories and information worth reading are available on HSE Now, the recently launched SPE online publication specially dedicated to HSSE–SR. HSE Now can be found at www.spe.org/hsenow. I wish you enlightening reading, and I hope to see you at the next international SPE HSE conference, 17–19 March 2014, in Long Beach, California. That will be the place to improve your skills and network with your peers, regardless of whether you are an HSE professional. Remember, HSSE-SR is everyone’s business. Have a safe journey until then. Recommended additional reading at OnePetro: www.onepetro.org. SPE 163771 Why Culture Matters by Howard Duhon, Gibson Applied Technology & Engineering SPE 157402 Five Reasons We Are Not Getting to Zero by Norman W. Ritchie, vPSI Group SPE 156765 Care and Concern for People We Will Never Meet—Process Safety in the Design of the Wheatstone Platform by Kevin Stevenson, Chevron SPE 156133 Health Performance in the Oil and Gas Industry—The Results by Alison Martin, Tillies Consultancy SPE 164947 Identification and Management of Environmentally Critical Elements (First Technical Guidance on ECEs) by Cameron Stewart, Energy Institute, et al. SPE 164938 Monitoring the Environmental Impact of Offshore E&P Discharges Through Innovative Techniques by Marie-Charlotte Alboussière, Total, et al. SPE 157573 Development and Maintenance of a Sediment-Toxicity Test for Monitoring Synthetic-Based Drilling Fluids by John Candler, M-I Swaco, et al.

Technology Focus: Drilling and Completion Fluids (November 2011)

Technology Focus When you take a look at the oil industry these days, what is the one thing you hear and read about the most? “Shale plays.” Operators are developing resources, purchasing acreage, and purchasing companies that have acreage in the USA and in countries around the world, now more than ever before. For long-term economic stability of these projects, they need to be drilled as inexpensively and as fast as possible—basically, they need to be “factory-type wells.” The main fluid-related challenges associated with shale drilling are rate of penetration (ROP), shale stability, torque and drag, and waste management. Many of these wells are being drilled with nonaqueous fluids (NAFs) to meet these challenges, with the only real issue being waste management. However, there are technologies being used that reduce the amount of waste generated with NAFs, such as premium solids-control systems and thermal-desorption methods. In an effort to eliminate NAF waste-management issues, drilling-fluids companies have developed fit-for-purpose water-based drilling fluids for each of the major shale plays. The shale regions around the world vary in depth, mineralogy, temperature, and other characteristics, and a single fluid formulation does not fit all circumstances. Each fluid is customized to the unique characteristics of a particular shale region. Fluids companies have specific products and chemistries that are designed for a specific type of shale and drilling operation. As technological advances enable exploitation of shale resources around the world, the challenge will be to find the most-cost-effective solution. As always, the lowest overall well cost may not result from the lowest-cost-per-barrel drilling fluid. One has to take into account ROP, torque and drag, wellbore stability, and waste management when determining the most-cost-effective solution. There were many good papers written this year, and I have tried to choose a variety of universal topics. Please take time to read them and the papers listed as additional reading. Drilling and Completion Fluids additional reading available at OnePetro: www.onepetro.org SPE 144214 • “Crude-Oil-Compatibility Method Significantly Minimizes Volumes Required” by Katrina Schultz, SPE, Baker Hughes, et al. SPE 142008 • “Chemical Properties Affecting the Environmental Performance of Synthetic-Based Drilling Fluids for the Gulf of Mexico” by P.B. Dorn, SPE, Shell, et al. SPE 139623 • “Drilling-Fluid Design Enlarges the Hydraulic Operating Windows of Managed-Pressure-Drilling Operations” by Doug Oakley, M-I Swaco, et al. SPE 139534 • “Preliminary Test Results of Nanobased Drilling Fluids for Oil- and Gasfield Application” by Md. Amanullah, SPE, Saudi Aramco, et al.

Design and Development of a Novel Process To Treat Drilling-Fluid Slops: A Positive Environmental and Economic Impact

Summary Slop mud, created by water contamination of invert drilling fluids during displacement and cleaning activities, has been successfully treated at source to recover the drilling-fluid phase and water phase. This method included treating the slop mud with a biodegradable demulsifier. The recovered drilling fluid can be reconditioned to acceptable properties for reuse or can be sent for disposal. The recovered/separated slop water phase is contaminated with hydrocarbons and cannot be discharged in an offshore environment unless it meets the discharge criteria of < 30 mg/L of oil in water. Thus, it becomes imperative for the operator to treat the water at source, reduce the enormous expenses associated with transportation/disposal, and embark upon a potentially significant environmental issue. This was achieved by development of an on-site treatment process including filtration, ozonation, and phase separation. A synthetic-based drilling fluid contaminated with water was separated with a biodegradable demulsifier. The addition of the surfactant resulted in phase separation (i.e., separated drilling-fluid and water phases). As tested by the approved International Organization for Standardization (ISO) method, the separated water phase was found to have oil-in-water content of 4,000 mg/L, which is unacceptable for discharge. The separated water then was treated with ozone. The ozone-treated water was allowed to separate in two phases (i.e., clarified water phase and organic rich phase). The oil-in-water content of the clarified ozone-treated water phase was found to be 30 mg/L, thus reducing the oil-in-water content by 99%. This paper will present the demulsification methodology, the chemistry of ozonolysis, and the results obtained to meet or exceed the oil-in-water discharge limits of 30 mg/L. The environmental and economic impact of the process will be discussed.

Olefin-Based Synthetic-Drilling-Fluids Volumetric Behavior Under Downhole Conditions

Summary Usual practice in drilling engineering is to determine drilling-fluid density at surface conditions assuming that drilling-fluid density does not change with changing downhole conditions. This assumption may result in inaccuracy while estimating static and dynamic pressures in the wellbore, especially when synthetic-based drilling fluids are used. Inaccurate estimation of the pressure profile in the annulus can lead to severe well problems such as kicks, drilling-fluid losses, and wellbore instability. In addition, inaccurate pressure-profile estimation can affect the success of managed-pressure-drilling (MPD) operations, which require real-time knowledge of wellbore pressures to keep wellbore pressure between formation pore and fracture pressures using a control choke placed on the return line of the annulus. Effects of pressure and temperature on volumetric behavior of two olefin-based synthetic oils are investigated in this study using a mercury-free pressure/volume/temperature (PVT) system. The olefin-based synthetic oils used in this study are C16C18 internal olefin (IO) and C12C14 linear alpha olefin (LAO). To simulate deep offshore situations, the temperature is ranged between 25 and 175°C, while the pressure is ranged between 0 and 14,000 psig. In addition, volumetric performances of olefin-based synthetic-oil systems under investigation are compared with those of water, brine solution, mineral oil, diesel oil, and n-paraffin-based oil under similar conditions. The study shows that the volumetric properties of synthetic-based oils are more sensitive to pressure and temperature conditions compared to water, brine solutions, mineral oil, and diesel oil. Once emulsion systems containing synthetic-based oils are used, density change with respect to downhole conditions should be modeled to increase the reliability of pressure-profile calculations.

Effect of Oxidation On Explosion Potential And Barite Sag Reduction In Oil- And Synthetic-Based Drilling Fluids

Abstract Oil and synthetic-based drilling fluids are the drilling muds of choice in high pressure and high temperature wells. The hot drilling fluid is returned to the surface and is exposed to air in the mud tanks. Since the base liquids of these drilling fluid systems are expensive, they are used in many wells before disposal. The long exposure of the oil to air can result in a substantial oxidation of the oil; especially in hot reservoirs in summer temperatures. To simulate the oxidation of these drilling fluids, an experimental study was conducted in which 20 oil-based and synthetic-based drilling fluid systems which are used in Western Canada, were examined. The drilling fluid systems were aged in stationary reactors in the presence of one charge of air for 52 hours at 150 ºC and 13.5 MPa initial pressure. While rapid heat releases or explosions in the synthetic-based drilling fluids were observed, oil-based systems were safe under the conditions tested. The rheological properties of the drilling fluid samples after aging were compared with the original (before aging) samples. The results at an ultra low shear rate range of 0.0 – 0.2 s−1 and a high shear rate range of 0 – 4,000 s−1 are presented. It is shown that the aged drilling fluid systems exhibited a tremendous increase in viscosity at ultra-low shear rates. Furthermore, relatively low increases in viscosity at medium and high shear rates were observed. Introduction Demand for energy sources is increasing throughout the world at a rapid rate due to industrial development and population growth. The search for new sources of oil and gas on land and offshore, and also developing current resources, has intensified due to this increasing demand. Oil production involves two main phases of drilling operations; namely, exploration and development. The exploration phase operations determine the potential hydrocarbon reserves and include drilling of exploratory wells, whereas, the development phase operations include drilling of production wells once a hydrocarbon reserve has already been discovered. Drilling fluids are one of the essential components of the drilling operation. Inappropriate design of a drilling fluid system can lead to numerous problems such as stuck pipe, lost circulation, wellbore instability, gellation, insufficient hole cleaning, bit balling, barite sag, excessive torque and drag, corrosion, H2S contamination and plugging due to gas hydrates. Due to some underbalanced drilling applications that employ gasified liquids, oxidation of oil and synthetic-based drilling fluids has recently received some attention. Historically, in situ combustion(1) and high pressure air injection (HPAI)(2, 3) are two major areas in thermal enhanced oil recovery techniques where the oxidation of oils are of special importance. In these processes, it is of vital importance to know what effects the oxidation has on rheological properties of the oil, because it affects the mobility of the oil and, therefore, the recovery factor. In drilling fluids, in addition to changes in rheological properties, safety considerations and explosion potential require investigation. In the first phase of this research, the oxidation of different base oils was investigated.