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Drilling fluid selection and formulation (chemistry, properties)
This article, written by Dennis Denney, contains highlights of paper SPE 164716, ’Applications of Nanotechnology in the Oil and Gas Industry: Latest Trends Worldwide and Future Challenges in Egypt,’ by Abdelrahman Ibrahim El-Diasty, SPE, and Adel M. Salem Ragab, American University in Cairo and Suez University, prepared for the 2013 North Africa Technical Conference & Exhibition, Cairo, 15-17 April. The paper has not been peer reviewed. Precise manipulation and control of matter at dimensions of 1–100 nm have transformed many industries including the oil and gas industry. Nanosensors enhance the resolution of subsurface imaging, leading to advanced field-characterization techniques. Nanotechnology could greatly enhance oil recovery by use of molecular modification and by manipulating interfacial characteristics. Egypt’s oil consumption has grown by more than 30% in the past 10 years. Hydrocarbon reserves in Egypt have increased 5%/year over the past 7 years, while the average recovery factor remains at 35%. Nanotechnology is key to solving this production/ consumption imbalance. Introduction Nanotechnology is the use of very small pieces of material, with dimensions between approximately 1 and 100 nm, by themselves or by manipulation to create new larger-scale materials with unique phenomena enabling novel applications. A nanometer is one-billionth of a meter— a distance equal to two to twenty atoms laid down next to each other (depending on the type of atom). Nanotechnology refers to manipulating the structure of matter on a length scale of nanometers, interpreted at different times as meaning anything from 0.1 nm (controlling the arrangement of individual atoms) to 100 nm or more. Fig. 1 compares the scale of various items referenced to a nanometer. Engineered Nanomaterials Nanoparticles are the simplest form of structures with sizes in the nanometer range. In principle, any collection of atoms bonded together with a structural radius <100 nm can be considered a nanoparticle. The tiny nature of nanoparticles yields useful characteristics, such as increased surface area to which other materials can bond in ways that make stronger or lighter materials. At the nanoscale, size is a factor regarding how molecules react to and bond with each other. Suspensions of nanoparticles are possible because the interaction of the particle surface with the solvent is strong enough to overcome differences in density, which usually would result in a material either sinking or floating in a liquid-forming nanofluid. Nanofluids for oil and gas applications are defined as any fluid used in the exploration and exploitation of oil and gas that contains at least one additive with a particle size in the range of 1–100 nm. A few oilfield uses are described in the following. See the complete paper for additional uses and details.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
This article, written by Dennis Denney, contains highlights of paper SPE 166103, ’Evaluation of Annular-Pressure Losses While Casing Drilling,’ by Vahid Dokhani and Mojtaba P. Shahri, SPE, University of Tulsa; Moji Karimi, SPE, Weatherford; and Saeed Salehi, SPE, University of Louisiana at Lafayette, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. Casing drilling is a method by which the well is drilled and cased simultaneously. The small annulus from casing drilling can create a controllable dynamic equivalent circulating density (ECD). Casing-drilling technology enables obtaining the same ECD as with conventional drilling but with a lower (optimized) flow rate and lower rheological properties and mud weight. Frictional pressure loss during casing drilling was evaluated with computational fluid dynamics (CFD). Having accurate models for ECD, including the effects of pipe rotation and eccentricity in the annulus, is essential for success in these challenging jobs. Introduction Casing drilling builds on experience gained from drilling liners to bottom in troublesome holes. The technique was implemented for drilling a formation sequence of highly pressured shale followed by a depleted reservoir. The major problem when drilling depleted reservoirs is the narrow operational mud-weight window. With advances in top-drive systems, retrievable bottomhole assemblies, and polycrystalline-diamond-compact bits, the technology enables completing a well by use of casing as the drillstring. An often-reported benefit of casing drilling is significantly fewer lost-circulation problems. The wellbore-plastering effect that casing drilling offers can enable drilling depleted zones while causing less formation damage. Plastering also enhances pressure containment by smearing the smaller drill cuttings into the pore spaces. The aim of this study was to simulate the casing-drilling operation through CFD modeling to evaluate the combined effect of eccentricity and pipe rotation on the velocity profile of a non-Newtonian fluid. Approach Initially, the geometry of casing drilling was constructed for a given wellbore condition. Then, the domain was discretized such that the result would not be grid dependent. A series of cases was designed to compare the CFD model with the analytical solution and validate the discretization scheme. Then, the non-Newtonian-fluid (yield-power-law model) simulation was run. Thereafter, an effort was made to analyze the effect of eccentricity and pipe rotation on the yield-power-law fluid. Assumptions In drilling operations, continuous fluid circulation through the annulus results in steady-state flow. In the shallow top-hole section, the fluid can be treated as an incompressible fluid. The simulated laminar-flow regime verified the CFD results with the analytical solution. It was assumed that a single-phase fluid flows through the annulus and that the pipe geometry provides a uniform concentric annulus along the test section. For simplicity, the effects of drill cuttings were neglected in the simulation to be able to validate the CFD results with the analytical solution. Initially, the casing was treated as stationary (no pipe rotation) with a no-slip condition at the walls (both inner-pipe and wellbore). The pipe and the wellbore were assumed to be smooth. Also, the geometry was held uniform along the pipe (i.e., the effect of tool joints on pressure loss was neglected). The pipe section was considered to be 5 or 10 m long.
- Well Drilling > Drilling Operations > Running and setting casing (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
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.
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.45)
- Europe > United Kingdom > North Sea (0.25)
- Europe > Norway > North Sea (0.25)
- (3 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Health, Safety, Environment & Sustainability > Environment > Waste management (1.00)
- Well Drilling > Drilling Fluids and Materials > Solids control (0.89)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.83)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 155320, ’Offshore Drilling and Well Testing of an HP/HT Gas Well: A Case Study,’ by Prerak H. Shah, SPE, Harsh T. Pandya, SPE, Harsh Sharma, and Arpit Saxena, SPE, Gujarat State Petroleum Corporation, prepared for the 2012 SPE Oil and Gas India Conference and Exhibition, Mumbai, 28-30 March. The paper has not been peer reviewed. With exploration in harsh environments and consequent high-pressure and high-temperature conditions, calculating reservoir properties has become complex and changes in pressure-transient response need to be understood and appreciated by taking appropriate measures. The challenges arising with drilling and testing of high-pressure/high-temperature (HP/HT) gas wells that produce hydrogen sulfide (H2S) and carbon dioxide (CO2) in the Krishna Godavari basin are discussed. Introduction In the exploration campaign in the Krishna Godavari basin off the east coast of India, four wells were drilled, discovering a very tight gas reservoir with an average pressure of 12,000 psi and an average re-corded temperature of 360°F and classified as an HP/HT reservoir, as shown in Fig. 1. This paper discusses the experience drilling four wells with a jackup rig in average water depth of 60 m. Well-A was the first well. Well-B dis-covered and flowed gas from stratigraphy below the section encountered in Well-A. Well-C encountered the same sands found in Well-A, and additional shallower sands not encountered in Well-A or Well-B were discovered. The reservoir section is overlain by shale. Well-A was drilled in six sections because it was the first exploratory well; the other three wells were drilled in five sections. All wells had sections of 36-, 26-, 17½-, 12¼-, and 8½-in. hole and Well-A had an additional 6-in. section. These sections were cased with 30-, 20-, 13⅜-, 9⅝-, and 7-in. liner casings, respectively, and Well-A included a 5-in. liner. The reservoir section expected in 8½-in. hole from seismic and log data was proved while drilling Well-A and was appraised in Well-B, Well-C, and Well-D. Well-A and Well-B were drilled to total depth with water-based mud (WBM). The 12¼-in. section of Well-C was drilled with WBM, while the 8½-in. section was drilled with synthetic-oil-based mud (SOBM). The shale sections and reservoir section in Well-D were drilled using SOBM. The mud program was designed on the basis of the pore-pressure-leakoff-test (LOT) vs. depth chart shown in Fig. 2.
- Geology > Geological Subdiscipline (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.71)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > HP/HT reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139932, ’Drilling Highly Depleted Formations With Engineered- Particle Nonaqueous Fluids: South China Sea,’ by Michael R. Niznik, SPE, Adela Lawrence, SPE, and Sabine C. Zeilinger, SPE, ExxonMobil, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. A new engineered-particle nonaqueous-fluid (EP-NAF) system was used in the Malay basin of the South China Sea to drill through highly depleted sands at elevated densities. The fluid contains sized particles to bridge and prop open fractures as they occur during actual drilling operations. Formation integrity is gained immediately and does not require additional critical-path rig time. Background and Well-Design Overview The Malay basin in the South China Sea contains multiple oil and gas accumulations, some of which have been on production for several decades. Many of these mature fields have economically recoverable quantities of hydrocarbons but are challenging because depleted zones are adjacent to formations prone to wellbore instability. A four-well infill development program was planned in one of these mature fields. The field is 200 km offshore in 70 m of water. Several platforms were installed to develop the field, which has been producing for more than 20 years. Typically, tender-assisted platform rigs are used in this field. Well-Design Challenges and Planning All proposed wells would be side-tracked from existing donor wellbores. A variety of casing sizes was used in the donors, and exact cement tops were not known. The exact sidetrack point was engineered to take into account collision avoidance of offset wells, cement behind casing, formations in which to sidetrack, and dogleg requirements to meet geology and reservoir objectives. The target reservoir was the Group-J sands that lie below the Group-I reservoir, which was completed and put on production more than 20 years earlier. The pore pressure of the Group-I reservoir in the area where the proposed wells would penetrate was determined to be depleted to a 3.7-lbm/gal gradient. The target Group-J sands also were slightly depleted to a 6.8-lbm/gal gradient because of production in adjacent fault blocks. The targeted Group-J reservoir has lower-permeability sands compared with the Group-I reservoir above it. Horizontal wells were planned to intersect additional reservoir footage and to maximize productivity and reserves recovery. The Group-J sands are highly consolidated, and modeling, along with offset-well analysis, determined that sand control would not be required. The wells could be completed open hole with predrilled liners, which minimized completion complexity and cost.
- Asia > China (1.00)
- Asia > Malaysia > South China Sea (0.45)
- Europe > Netherlands > North Holland > Amsterdam (0.24)
- North America > United States > Texas > Dawson County (0.24)
- Well Drilling > Well Planning (1.00)
- Well Drilling > Pressure Management (1.00)
- Well Drilling > Drilling Operations (1.00)
- (5 more...)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145969, ’Drilling With a Balanced-Activity Invert-Emulsion Fluid in Shale: Is It Sufficient for Maintaining or Enhancing Wellbore Stability?,’ by Terry Hemphill, SPE, Halliburton, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. Most wellbore-stability problems encountered while drilling occur in shale formations. Invert-emulsion fluids (IEFs) are used to drill reactive shales. Testing of a deepwater shale was performed with a new apparatus, which allows shale samples to be tested under downhole conditions. Results show that even at an activity level higher than the known shale-activity level, water was able to enter the shale and weaken it. The “chemomechanical-balance” concept was used to explain measured results in terms of the coupling of shale-mechanical properties and IEF chemical activity and to explain the resulting consequences of activity-level selection for IEF. Introduction The interaction of invert-emulsion drilling fluids with exposed shales has received much study because well-bore-stability problems occurring in shale are in the 80% range of all cases cited in literature. While usually not found in the reservoir sections, when these shales become unstable, significant nonproductive time is spent in efforts to stabilize the wellbore, and sometimes entire drilling intervals are lost. To understand the interaction of IEFs with shale during the drilling process better, it is helpful to review the pertinent theories used to describe such action. Semipermeable-Membrane Theory. At the face of the shale that is exposed to aqueous fluid, a semipermeable membrane exists that regulates the flow of water in or out of the specimen. Fluids having high membrane efficiencies, such as IEFs, have the ability to pull water from the rock efficiently. But fluids with low membrane efficiencies, such as common water-based drilling fluids, do not pull water efficiently. There is still uncertainty about whether the membrane is provided by the IEF or by the shale itself. Osmotic-Pressure Theory. Fluids having lower chemical activity compared with the shale-pore fluid can generate significant amounts of osmotic pressure that can be used to remove water from the rock. Conversely, an IEF with higher chemical activity in the drilling-fluid water phase than in the shale-pore water can push water into a shale.
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142033, ’Study and Application of High-Density Acid in a Deep HP/HT Well,’ by Xingsheng Cheng, Yongping Li, Yunhong Ding, SPE, and Mingguang Che, Langfang Branch, Research Institute of Petroleum E&D, PetroChina, and Fuxiang Zhang, SPE, and Jianxin Peng, Tarim Oilfield Company, PetroChina, prepared for the 2011 SPE European Formation Damage Conference, Noordwijk, The Netherlands, 7-10 June. The paper has not been peer reviewed. The KKY reservoir in the Tarim oil field in western China is a deep high-pressure/high-temperature (HP/HT) dolomite reservoir. The formation was damaged with heavy mud during drilling, and matrix acidizing could not clean the skin effectively. To decrease the surface treating pressure to a safe level, a new high-density-acid system was developed. Extensive laboratory testing was conducted to evaluate its corrosion-inhibition and friction-reduction capacities, rheological properties, and stability. The new weighted acid ensured successful acid fracturing of the KKY reservoir. Introduction The KKY is a deep dolomite condensate/gas reservoir at a depth greater than 6000 m with reservoir temperature and pressure of approximately 150°C and 110 MPa, respectively. The formation suffered extreme damage because of the use of heavy mud and the existence of natural fractures. At first, matrix acidizing was used to eliminate the skin, but treatments were limited by the high pressure required. Production increased somewhat, but dropped quickly and could not be sustained. Analysis showed that matrix acidizing could not remove the damage completely; therefore, acid fracturing was investigated. It was determined that an acid-fracturing treatment could not be implemented with conventional acid because the surface pressure exceeds the working-pressure capability of conventional 103.4-MPa fracturing equipment. A high-density-acid proposal was developed to reduce the wellhead pressure. High-Density Acid Weighting Agent. Generally, high-density acids are blended by adding acid into high-density concentrated halide brines, such as sodium chloride, calcium chloride, sodium bromide, calcium bromide, or a combination of zinc bromide and calcium bromide, among others. Because the reservoir is dolomite, the main processing acid is hydrochloric acid (HCl), and all the salts and brines mentioned above can be used. The selection of salts or brines is based primarily on the required properties of weighted acids and on cost effectiveness. Considering the need of density in the reservoir and the density of different brines, calcium chloride and some bromide were selected as weighting agent according to the properties of individual wells. The density of weighted acid can be adjusted between 1.25 and 1.55 g/cm by regulating the type and quantity of brine.
- Asia > China (0.76)
- Europe > Netherlands > South Holland > Noordwijk (0.25)
- Geology > Mineral > Halide (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.66)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > HP/HT reservoirs (1.00)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142832, ’Magnesium Peroxide Breaker for Filter-Cake Removal,’ by Shrikant K. Mahapatra, SPE, ADMA-OPCO and Bela Kosztin, SPE, PDO, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed. Commonly used drill-in fluids (DIFs) typically contain starch, xanthan, and sized calcium carbonate. Although DIF is inherently less damaging than conventional drilling mud, relatively impermeable filter cakes are deposited on the borehole wall. A common practice to minimize such damage is applying acid (i.e., external breaker) or a strong oxidative breaker (i.e., internal breaker) system to dissolve filter-cake solids and biopolymers. Magnesium peroxide is an internal breaker and is classified as an oxidizer, which decomposes slowly to release oxygen. The magnesium peroxide, when exposed to an acidic solution, releases hydrogen peroxide that degrades the polysaccharide-type polymers and removes the external filter cake. Introduction To realize the full potential of openhole horizontal completions, formation damage caused by residual filter cake must be removed. A common approach to mitigate such damage is application of strong organic acids, ester-generated organic acids, chelates, enzymes, and combinations of these or different oxidative breaker systems to dissolve/destroy filter-cake solids and biopolymers. Two basic methods are applied to deteriorate filter cake that contains polymers. External breaker placed in contact with the surface of the filter cake. Internal breaker deposited as an integral component of the filter cake. Peroxide Chemistry Magnesium peroxide is a very stable strong oxidizer and can be used as an internal breaker. At medium or low temperatures, it remains inactive when added to polymer and sized-solids DIF, and thus becomes an integral part of the filter cake as it is deposited. According to the particle-size distribution and active-material content, there are many types of magnesium peroxide available. It is best if the selected type matches with the pore-size distribution of the drilled reservoir section and with the drilling rig’s solids-control system. The particle-size distribution is affected by the volume and particle-size composition of the other bridging materials also. Because of the extremely low solubility of magnesium peroxide, it remains stable for extended periods of time while in an alkaline environment and within the filter cake. Upon contact with hydrochloric acid (HCl), the solid peroxide decomposes to form hydrogen peroxide. Hydrogen peroxide generates in-situ oxygen, which attacks starch and xanthan polymers. Autoxidation occurs as the polymer is exposed to the oxygen.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125068, ’Proppant Transport in Slickwater Fracturing of Shale-Gas Formations,’ by Adam Dayan, Shaun M. Stracener, and Peter E. Clark, SPE, University of Alabama, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed. Predicting proppant transport is important in both treatment design and post-treatment analysis. The transport process has been studied since the late 1950s, and much has been learned from those simple laboratory models. There are indications that fracturing in gas-shale plays can produce complex fracture networks. To study how the slurry travels through the network, a small 1D fracture model with bifurcation was constructed along with a larger 3D slot model. Introduction It has been shown that fracture-width variation has a larger role than convection with respect to proppant placement. In nonsettling slurries, the motion of proppant-laden fluids into a fracture is influenced strongly by fracture-width variations. Therefore, width variations should influence settling slurries in the same manner. Also, the trajectories of both types of fluids will be influenced strongly by height growth and high-fluid-loss zones that will attract fluid flow. In gas shales, fracture bifurcation hinders understanding of and predicting proppant transport. Noncrosslinked Fluids Low-viscosity fluids can be pumped in laminar or turbulent flow, although turbulent flow may not persist away from the wellbore. The viscosity and structure of these fluids allow particle settling. Convection and particle settling act in the same direction, so the process is considerably more complex than simple settling. Particle Settling. Several factors influence particle settling in Newtonian and non-Newtonian fluids. The density difference between the particle and the carrier fluid, the square of the particle diameter, and the fluid viscosity are important. In addition, the presence of boundaries (walls) and particle/particle interaction (hindered settling) can affect particle settling in fracturing fluids. With non-Newtonian fluids, viscosity and viscoelasticity make the problem more complex. Non-Newtonian Fluids. Most of the polymeric thickening agents used in the oil field exhibit shear thinning over some range of shear rates. As an additional complication, noncrosslinked polymeric fluids can exhibit viscoelasticity, for which the influence on the settling velocity is not predicted easily. Three distinct regions of viscosity behavior exist with respect to shear rate that most, if not all, non-Newtonian fluids exhibit: a power-law region bounded by upper and lower Newtonian regions. The range of the power-law region can vary by orders of magnitude depending upon the fluid. While the power-law region is most often assumed to occur within the boundaries of this region, the shear rate caused by particle settling falls outside this region. The small particles and relatively low shear rates in the fracture allow the high-shear-rate upper Newtonian region to be ignored safely. However, fluid behavior in the low-shear-rate portion of the power-law region and in the lower Newtonian region is likely to be significant in determining the particle-settling velocity. The velocity profile for a non-Newtonian fluid tends to be flatter in the center with a near-zero shear rate. The zero-shear viscosity of the fluid is even more important in the settling of particles traveling in the center of the flow.
- North America > United States > Louisiana > Orleans Parish > New Orleans (0.25)
- North America > United States > Alabama (0.25)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 98318, "Effective Stimulation of High-Temperature Sandstone Formations in East Venezuela With a New Sandstone-Acidizing System," by S.A. Ali, SPE, and C.W. Pardo, SPE, Chevron Energy Technology Co., and Z. Xiao, SPE, F.E. Tuedor, SPE, A. Boucher, SPE, S.A. Al-Harthy, B. Lecerf, and G. Salamat, SPE, Schlumberger, prepared for the 2006 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 15–17 February. Wells in this eastern Venezuela oil field have a bottomhole temperature of approximately 230°F and varied mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate-scale damage have been reported. A novel chemical system was developed to stimulate these high-temperature sandstone reservoirs. Introduction Most of the wells in this field in Maracaibo, Venezuela, have several perforated intervals covering up to 1,000 ft, with a net perforated interval of up to 500 ft. The mineralogy varies from interval to interval, with 4 to 16% calcium carbonate (CaCO3), 6 to 18% clays (mainly kaolinite), 5 to 10% feldspars, and 2 to 5% siderites in some wells. Reservoir pressures range from 800 to 2,500 psi, and skin values vary across the zones. Permeability varies from 1 to 200 md among the zones. The main formation-damage mechanisms were identified as fines migration (80 to 90% production decline after treatment) and CaCO3 scales, mainly from loss of workover fluids. Various formulations of mud acid, organic-clay acid, and solvents are used to treat these wells, with mixed results. The new sandstone-acidizing system was developed to treat multilayered high-temperature (200 to 375°F) reservoirs with long production intervals and complex mineralogy. The new sandstone-acidizing fluid uses a single-stage placement process, has less precipitation tendency and reduced tubular and production-equipment corrosion, and reduces exposure of hazardous fluids to wellsite personnel and the environment. A comprehensive laboratory study, which included acid-solubility tests, X-ray diffraction (XRD) analysis, batch reaction kinetics, fines-migration tests, and core-flow tests, was conducted on field cores to evaluate the performance of this sandstone-acidizing system and compare it with currently used systems. Experiment Twelve core plugs were used from the formation sand in the oil field. Six plugs were from the 7,951- to 7,953-ft interval, five from the 7,723- to 7,727-ft interval, and one from the 7,757- to 7,758-ft interval. All samples were 1 in. in diameter and approximately 2 to 3 in. long. These core samples were classified into groups of high- and low-permeability sands, although a slight difference in physical appearance was observed in the laboratory. Acid solubility tests were run on 10 samples. Mineralogical information is very important in sandstone-acidizing treatments. XRD was used to quantify the mineralogical composition of the core samples. Typical minerals in sandstone rock include silica (quartz), feldspars (plagioclase, K-feldspar), clays (kaolinite, illite, chlorite, smectite, and mixed-layered illite and smectite), zeolites, micas, carbonates (dolomite, calcite), sulfides, and sulfates (gypsum, anhydrite, and barite).
- South America > Venezuela > Zulia > Maracaibo (0.25)
- North America > United States > Louisiana > Lafayette Parish > Lafayette (0.25)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate (1.00)