This article, written by Dennis Denney, contains highlights of paper SPE 168182, "Sulfide Scale Coprecipitation With Calcium Carbonate," by C. Okocha and K.S. Sorbie, SPE, Heriot-Watt University, prepared for the 2014 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 26-28 February. The paper has not been peer reviewed.
Mixed carbonate-/sulfide-scale problems have been reported when water is produced from carbonate reservoirs. This study presents interactions of lead sulfide and zinc sulfide coprecipitating with calcite. The relationship between bulk precipitation and deposition on a metal surface of the mixed carbonate/sulfide scales was examined when the mixed scales began to nucleate, agglomerate, and grow. The nature of these mixed crystals may indicate that mixed sulfide scales tend to prefer forming in solution rather than adhering to metal surfaces in protected zones. Thus, the mixed sulfide scale may be controlled in one zone but be unprotected in other regions.
Carbonate reservoirs contain approximately 60% of the world’s remaining oil and gas reserves. Scale precipitation during oil and gas production is costly. Conventional scales, such as sulfate and carbonate, are well-known and have been researched and reported extensively. Sulfide scales are less studied, and their effect on conventional scales (formation and inhibition) is relatively unknown.
The effects of carbonate/sulfide coprecipitation in bulk solution and on metal surfaces are presented. Sulfide was coprecipitated with barium sulfate (BaSO4), and the effects on formation and inhibition of the BaSO4 crystals were monitored. The relationship between bulk precipitation and surface deposition of the mixed carbonate/ sulfide scales was examined also. Both carbonate- and sulfide-scale problems have been reported when water is produced from carbonate reservoirs, and the use of scale inhibitors to control this problem is relatively common.
This article, written by Dennis Denney, contains highlights of paper SPE 169748, "Kinetics and Inhibition of Ferrous Sulfide Nucleation and Precipitation," by Qiliang Wang, Zhang Zhang, Amy Kan, SPE, and Mason Tomson, SPE, Rice University, prepared for the 2014 SPE International Oilfield Scale Conference and Exhibition, Aberdeen, 14-15 May. The paper has not been peer reviewed.
Ferrous sulfide (FeS) precipitation increases during shale-gas and -oil production because of increased biologically and thermally induced sulfide production. Although FeS scale is abundant, little is understood about its precipitation and inhibition properties. A plug-flow apparatus adds reliable data to the limited database of scaling kinetics in flowing pipes, and it provides a new method to study the effect of inhibitors in oil-production systems.
During oil production, mineral-salt precipitation (scale) builds up inside wellbores. It is very difficult to study the formation and inhibition of FeS because the experiments must be performed under rigorous anoxic conditions and the induction time is very short. Compared with common oilfield scales, FeS scale has distinctive characteristics. FeS can cause galvanic corrosion in the presence of water. FeS has several crystalline forms with different sulfur/iron ratios that result in different solubilities of FeS. Additionally, FeS particles are oil-wet and can be coated easily with oil or hydrocarbons; these coatings can act as a diffusion barrier that retards acid reaction with the scale.
To evaluate the risk of scaling in pipes, a plug-flow apparatus was used to investigate CaCO3-scale precipitation on stainless-steel tubes. In the study of CaCO3, a precoated plug-flow reactor provided a constant composition at the tubing exit, including constant pH, saturation index (SI), ionic strength, and surface area. The plug-flow system provided a feasible approach to study the kinetics of initial attachment and crystal growth. FeS had not been studied with a plug-flow system; therefore, it was important to develop a plug-flow setup to investigate FeS formation and precipitation, enhancing the limited database of scaling kinetics in flowing pipes.
To eliminate the influence of scale on oil production, scale inhibitors often are needed to minimize the scale buildup. The controlling method of scale inhibitors is to delay, reduce, or prevent scale formation. Scale inhibitors can prevent further growth of scale crystals by adsorbing onto the surface of the crystals. In addition to scale inhibitors, dispersants and chelating agents are applied to sequester metal cations, preventing them from reacting with anions. The objectives of this research were to investigate the effects related to the driving force on FeS precipitation in batch and plug-flow systems, and to conduct a series of laboratory studies on scale-inhibition approaches for FeS by use of commercial scale inhibitors and chelating agents.
This article, written by Dennis Denney, contains highlights of paper SPE 169759, "Extreme Challenges in FeS-Scale-Cleanout Operation Overcome Using Temporary Isolation, High-Pressure Coiled Tubing, and Tailored Fluid Systems," by Mustafa Buali, Noel Ginest, SPE, Jairo Leal, and Oscar Sambo, Saudi Aramco, and Alejandro Chacon and Jose Vielma, Halliburton—Boots & Coots, prepared for the 2014 SPE International Oilfield Scale Conference and Exhibition, Aberdeen, 14-15 May. The paper has not been peer reviewed.
The gas-producing carbonate zones of the Ghawar field in eastern Saudi Arabia have been affected by extensive iron sulfide (FeS) scale deposition, reducing overall gas production and increasing risks during well interventions. Previous remediation attempts used workover rigs, which can be costly because of the time necessary for workovers and lost production. Hydrogen sulfide (H2S) levels (2 to 5%) in the reservoir also contribute to higher costs and risks with the use of workover rigs. H2S in the reservoir poses a safety concern with the returns at surface and a concern with potential corrosion of the coiled tubing (CT) and completion. Therefore, the safest and most economical method was deemed to be mechanical descaling with CT.
Two wells were descaled mechanically by use of CT. Each well involved four major challenges: low reservoir pressure, higher reservoir temperature, horizontal openhole completion, and highspecific- gravity (3.7 to 4.3) scale. The low reservoir pressure required payzone isolation to enable circulating out the heavy scale and to minimize fluid losses to the formation. With a bottomhole temperature as high as 310°F, the operational envelope of temporary chemical packers in combination with lost-circulation materials (LCMs) to isolate the openhole section had to be expanded. Following mechanical descaling with CT, the final challenge was cleaning out the LCM in the horizontal open hole and bringing the well back to maximum gas production by use of pinpoint stimulation techniques.
Many scale samples have been collected and characterized throughout the years with X-ray diffraction (XRD), X-ray fluorescence, scanning electron micrographs, and microscopic methods (thin section). Although the exact chemical composition of the scale changes from well to well and varies with depth in a given well, the scale deposits are mixtures of many compounds, usually dominated by FeS minerals including pyrrhotite, troilite, mackinawite, greigite, pyrite, and marcasite.
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.
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.
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.
This article, written by Dennis Denney, contains highlights of paper SPE 163983, "An Approach to Practical Pressure-Transient Testing of Multiple-Fracture-Completed Horizontal Wells in Low-Permeability Reservoirs," by Richard Volz, Elvia Pinto, and Omar Soto, SPE, BP America, and J.R. Jones, SPE, NSI Fracturing, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28-30 January. The paper has not been peer reviewed.
A common well-completion configuration for shale-gas wells is a horizontal well with multiple transverse hydraulic fractures. This configuration is becoming common for tight gas reservoirs. Pressure-transient testing of this completion configuration has not been considered practical or useful because extracting completion parameters (e.g., fracture conductivity and fracture half-length) from the recorded response requires estimating the effective formation permeability. Estimating permeability directly from a buildup or drawdown test can be performed only if data from the radial-flow period, which reflects this parameter, are recorded. Unfortunately, for this completion configuration in a low-permeability reservoir, this flow period occurs only after extremely long shut-in or flowing times.
The usual shale-gas completion is a cased-and-cemented horizontal well, perforated with multiple perforation clusters. Each perforation cluster is treated with an independent fracture stimulation with a large volume of fluid and relatively low proppant concentration. The goal is to create an induced-hydraulic-fracture system, spaced along and covering the length of the horizontal well to provide a large, effective surface flow area in the reservoir. Interpreted microseismic images of these multistage-stimulation treatments indicate that, in some reservoirs, the fractures created at each perforation cluster have dominant transverse components. These dominant transverse components may or may not be interpreted to be overlain with or coupled to a more-complex system of secondary fractures. Even if the secondary system of more-complex fracturing occurs, the relative importance of this secondary fracture system and its relative contribution to the deliverability of the overall induced fracture system remain subjects of debate. It is equally difficult to establish or deny the importance of the overprint of a natural-fracture system to the flow response and performance of multiple-fracture horizontal wells (MFHWs) in unconventional reservoirs.
Therefore, the natural starting point for developing a useful pressure- transient- analysis method for horizontal-shale- well data would be on responses from horizontal wells affected by induced transverse fractures alone. Building viable pressure-transient-data interpretation methods for this simple base-case problem was the goal of this work. This interpretation must be accomplished before considering how to solve the more general cases that include induced- and natural-fracture complexity. The main issues in analyzing the pressure-transient response from an MFHW are the same as those with a vertically fractured well.
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.
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.
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.
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.
This article, written by Dennis Denney, contains highlights of paper OTC 24330, "Offshore Dry-Docking of FPSOs: A Response to Industry Needs," by T. Terpstra and E.A. Hellinga, Dockwise, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.
The large number of floating production, storage, and offloading units (FPSOs) commissioned more than a decade ago now require offshore-asset-integrity management and maintenance. The FPSOs were originally designed for continuous service for periods up to 25 years. However, although designed to strict criteria, structural and hull-maintenance shortcomings have become apparent, prompting remedial actions or extensive offshore-maintenance campaigns. An offshore-dry- docking concept was developed to lift an FPSO out of the water without disconnecting it from its mooring system and leaving the flowlines connected. The stable working platform allows work access to the FPSO hull, appendages, and mooring system.
The proposed offshore dry-docking concept lifts the FPSO out of the water by submerging the floating dry-dock vessel and moving it underneath the FPSO offshore without disconnecting the FPSO from its mooring system or flowlines, as shown in Fig. 1. The bowless concept of the dry-dock vessel with a high load-carrying capacity enables dry transportation of more-traditional semisubmersibles and other floating production units and FPSOs. The proposed offshore dry dock investigated the use of dry-transportation technology for offshore dry-docking of complete floating production units.
The largest heavy-transport vessel currently operating is designed to dry-transport offshore production facilities including ultraheavy semisubmersibles and FPSOs. In the past, an offshore unit would need to be wet towed from the fabricator to its production location. Scaling up the existing heavy-transport vessels was not sufficient because of the length of FPSOs, which can exceed 300 m. A bowless design is capable of transporting and offshore dry-docking FPSOs longer than 300 m, with the strength of the FPSO being the limiting factor. The design is shown in Fig. 2. With its bowless design, the total length of the Dockwise Vanguard (275 m) can be used. Its cruising speed of 12 knots is at least twice the speed of a wet tow. Floating cargoes with a maximum draft of 16 m can be loaded (not considering cribbing or grillage). The dry-dock vessel’s bowless design and the movable casings allow use of the vessel’s entire deck to transport units. Also, there are no vessel restrictions for overhang forward and aft. The bowless design is created by placing the crew’s accommodation on the extreme starboard side of the vessel together with the lifeboats.
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.
This article, written by Dennis Denney, contains highlights of paper IPTC 17091, "Extending Mature-Well Life by Innovative Slurry Design and Complex Coiled-Tubing Well Work," by M. Hairi A. Razak, Aulfah Azman, SPE, and Haryat Timan, Petronas, and M. Heikal Kasim, SPE, and M. Fakhrurazi Ishak, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
This article, written by Dennis Denney, contains highlights of paper IPTC 17096, "Production-Technology Challenges of Tight and Shale-Gas Production in China," by Hon Chung Lau, SPE, Shell (China) Projects and Technology, and Meng Yu, SPE, Shell International Exploration and Production, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.