Wax deposition is one of the major problems for onshore and offshore crude oil production. High molecular weight wax (HMWW) is commonly defined as a wax containing more than 40 carbons in its chemical structure. These types of wax are challenging to treat, as they form hard deposits that can be difficult to remove. Most paraffin inhibitors available in the market currently are not effective at inhibiting the formation and deposition of HMWW in oil production systems. This paper discusses extensive work on understanding HMWW characteristics and chemical methods to treat such deposits. A variety of wax characterization techniques, such as cold finger (CF), differential scanning calorimetry (DSC), cross polarized microscopy (CPM), and high-temperature gas chromatography (HTGC), were used to study the impact of inhibitor chemistry on wax characteristics.
Oil from South Texas with high wax content (8%) was evaluated using five different types of inhibitor chemistry. DSC and CPM were used to obtain the wax appearance temperature (WAT), and CF was used to deposit the HMWW and evaluate inhibition efficiency. HTGC results were obtained from the wax collected from CF to determine carbon distribution of the deposit. DSC of the wax was also performed to obtain the crystallization of the wax and estimate the wax content in the deposit.
Of the five chemistries evaluated, one showed good performance, with approximately 30% inhibition, while two polymers reduced the crystallization temperature and softened the wax deposit. The other two chemicals did not show any effects on the HMWW.
An essential part of any scale squeeze management strategy for any oilfield is the capability to accurately and precisely determine the residual scale inhibitor concentration in the produced fluids. This data in combination with ion analysis, suspended solids and productivity index is essential to determine the lifetime efficiency of scale squeeze treatments.
In recent years the stricter environmental regulations in the North Sea, coupled with the development and operation of more complex fields in harsh scaling environments, has led to increased use of environmentally friendly polymeric scale inhibitors. The accurate and specific analysis of polymeric scale squeeze inhibitors is known to be difficult and has led to the development of a toolbox of advanced scale inhibitor analysis techniques based upon liquid chromatography with mass spectrometric detection (LC-MS). These methods offer the potential to improve scale management capability in conventional and sub-sea fields through improved scale inhibitor detection at low levels.
In addition, mass spectrometric detection provides the ability to selectively detect chemical functional groups, contained within polymeric scale inhibitor molecular structures, which were previously not distinguishable. This is a distinct advantage for multiple scale inhibitor analysis capability in produced brines as certain chemical groups can now be used as tags without having to modify the chemistry of commercially available inhibitors.
The ability to detect polymeric scale inhibitors at very low MIC <1ppm with improved confidence has the potential for significantly extending scale squeeze lifetimes. In addition, this has now allowed highly efficient polymers to be used in field situations where scale squeezing had either been stopped or the lifetime was significantly compromised because of the lack of confidence in the scale inhibitor return profiles and the interferences from background reservoir Phosphorus or topside scale inhibitors.
Specific examples from North Sea fields, including both sub-sea and platform wells, will be presented where the scale management has been significantly improved through the application of the advanced LC-MS techniques. In addition, the use of the LC-MS techniques targeting specific chemical groups as molecular tags to enable multiple scale inhibitor detection for a range of quaternary amine acrylic co-polymers will be presented.
Martini, Matteo (Universite Lyon 1 Christian Hurtevent) | Brichart, Thomas (Universite Lyon 1 Christian Hurtevent) | Marais, Arthur (Universite Lyon 1 Christian Hurtevent) | Moussaron, Albert (Universite Lyon 1 Christian Hurtevent) | Tillement, Olivier (Universite Lyon 1 Christian Hurtevent) | Baraka-Lokmane, Salima (Total S.A.)
Mineral scale deposition in oilfield reservoirs has caused millions of dollars in damage every year. The most common remedy to the build-up of scale inside well bores and the surrounding reservoir is the periodical “squeeze” treatment by inhibitor additives. The real-time and on-site control of inhibitor concentration during production remains one of the big challenges. Indeed, current techniques of inhibitor monitoring that use elemental analysis appear too complex for an efficient long-term industrial solution. With this in mind, we have developed a simple and accurate method for scale inhibitor quantification in production waters based on the use of time-resolved fluorescence (TRF) tracers. The characteristic luminescence signature (lifetime value, emission and excitation spectra) of TRF tracers allows the reliable tracking of inhibitors additives. Moreover, their long-lifetime luminescence signal can significantly increase the signal to noise ratio thanks to the suppression of organic oil residual background emission. Our experimental tests on produced water collected from different sites confirm the detection of a larger variety of inhibitors i.e. for carboxylates, phosphonates and sulphonates by simple post-chelation with TRF tracers at low concentration. Indeed, the non-fluorescent inhibitor species have been switched to fluorescent compound by the addition of few amounts of tracer in order to be detectable and quantified at sub-ppm concentrations. The coupling between TRF tracers and specific TRF spectrofluorometer apparatus then open new and accurate ways for the online and/or on-site monitoring of scale inhibitors for better risk management of flow assurance during production.
Borate-crosslinked gels are preferred for hydraulic fracturing treatment of wells over metal-crosslinked gel because of their ability to reheal after shear and their reduced proppant pack damage. Conventional monoborate-crosslinked fluid is mostly limited to wells with low to medium bottomhole temperatures (120 to 200°F), while polyborate-crosslinked fluid is applicable at moderate to high temperatures (250 to 350°F). Recent work has found that the viscosity of conventional borate-crosslinked fluid underwent sequential viscosity loss at room temperature with stepwise pressure increases from 500 to 10,000 psi. This compromise in viscosity at high pressure can undermine fracture geometry as well as proppant transport and distribution in created hydraulic fractures. Also, it will be interesting to carry out this type of study under high-temperature conditions.
We reported in SPE 140817, 164118, and 168186 a high-temperature-tolerant polyamino-boronate crosslinker (PAB) containing multiple boron sites capable of interacting with multiple polysaccharide strands to form more complex crosslinking networks at lower polymer loadings than conventional fluids. Two crosslinkers constituted with different polyamine backbones (tetraethylenepentamine and tris-(2-aminoethyl)amine) were synthesized and crosslinked with hydrated guar. The optimized rheology was investigated at 250°F under a pressure ramp of 500 to 10,000 psi. The results indicate that viscosity of a 30 pound per thousand gallon (ppt) PAB-crosslinked guar is sustained up to 7000 psi at 250°F, whereas viscosity of conventional 30 ppt guar crosslinked by conventional borate crosslinkers fluid declines on ramping pressure from 500 to below 5000 psi.
The detailed results of the rheology tests at high temperature and pressure, 11B NMR of synthesized PAB crosslinkers and intermediates, as well as fluid chemistry will be discussed in this paper.
The modern horizontal multistage well is a main contributor to the recent transformation of North American oil and gas production. The large fracturing stage volume that defines unconventional wells, crossed against the increasing numbers of stages and laterals per pad, has dramatically increased the demand for fracturing materials such as sand, friction reducers, and gelling agents, and most especially water. At the same time, operators face increasing accumulations of produced water, which presents as water cut from more mature assets. It is therefore natural to propose using produced water as mixwater for fracturing fluids in new completions, but in practice this plan has met with two major barriers: first, regulatory and logistical hurdles concerning the storage, handling, and potential environmental impacts of the volume of produced water required to complete a modern well (millions of gallons per lateral), and second, technology gaps in the applied chemistry of completion fluids, particularly in crosslinked gels.
This paper reports the completion of a two-lateral well in the Williston Basin where produced water, filtered but otherwise untreated, was used throughout the slickwater and crosslinked components of about sixty hydraulic fracturing stages.
Proppant was successfully placed in all perforated zones in the Bakken and Three Forks formations, using a “hybrid” design that employed seven million gallons of water (of which 2.2 million gallons were crosslinked). Production figures for the well are satisfactory, and this is discussed in the context of fluid-related completion quality. This paper will concentrate on the development and implementation of a metal crosslinked fracturing fluid that shows excellent stability at typical Bakken conditions. We will present a comparison to conventional guar-borate systems.
The promise of this approach has many potential benefits. First, completion costs are decreased as freshwater sourcing and produced water disposal charges cancel each other. Second, far fewer truck trips are necessary to transport water. Third, the industry no longer requires fresh water sources or disposal wells where this technique is employed.
In many areas water used for steam flood injection has varied concentrations of dissolved silicon (Si), which can form silica scale, reducing thermal efficiency, and lowering steam quality. Scale inhibitors are typically used today, but removal of Si may be a more cost-efficient process to reuse the water, especially in areas with limited fresh water availability. Removing Si in the water treatment plant before steam generation can lead to higher quality steam at lower costs and result in better production.
Typical chemical precipitation methods have been reported for Si removal by adding different coagulant compounds that contain elements such as aluminum (Al), iron (Fe) or molybdenum (Mo). In general, the chemical precipitation method needs high volumes of coagulants and generates considerable amounts of sludge, and may also input extra compounds or ions into the treated water. Electrocoagulation (EC) has been claimed for Si removal, but low conductivity water (or low concentration of total dissolved salt (TDS)), as seen in steam injection systems, is not well-matched to traditional EC systems.
In this paper, a uniquely designed electrocoagulation (EC) system with non-sacrificial electrodes and sacrificial material was tested for Si removal from steam injection water. This EC system has been shown to be highly flexible and efficient for treating waters with TDS levels from 3,000 to over 300,000 mg/L, especially for Si, Fe, and suspended solid removal. The water in this case was hot (180°F), low TDS (<6,000mg/L), and had 60 to 80 mg/L of Si. Both laboratory scale testing and pilot field trial showed efficient Si removal from the water to less than 2 mg/L at varied temperatures. Significant hardness removal was also achieved during the same process. Compared with chemical precipitation methods, this unique EC system used fewer chemicals, generated less sludge, and provided a higher quality of effluent water.
Successful liner cementing in unconventional shale wells is strongly dependent on slurry stability. A delayed-release, high-temperature suspending agent was developed that provides viscosification and stabilization of the slurry without causing excessive viscosification and mixing problems at the wellsite. The suspending aid was prepared from water-soluble, thermally stable monomers copolymerized with degradable crosslinking monomers. The crosslinks degrade as the temperature of the slurry increases, ultimately resulting in dissolution of the polymer and concomitant slurry viscosification. The performance of the suspending aid was demonstrated by means of laboratory testing under typical Eagle Ford shale conditions. Improvements were observed in terms of fluid-loss control (54 cc/30 min [control] to 28 cc/30 min), free fluid (5% [control] to 0%), sedimentation (?? 5.2 lbm/gal [control] to ?? 0.2 lbm/gal), and consistometer off/on tests. Three field examples from the Eagle Ford are presented where the suspending aid was used to establish the desired mud-spacer-cement rheological hierarchy at bottomhole circulating temperature (BHCT); provide sufficient slurry stability to set the liner top plug, circulate out excess cement, and produce a competent cement sheath; and improve the mixability and stability of a barite-weighted spacer.
Kadhum, Mohannad J. (University of Oklahoma) | Swatske, Daniel P. (University of Oklahoma) | Chen, Changlong (University of Oklahoma) | Resasco, Daniel E. (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma) | Shiau, Ben (University of Oklahoma)
Carbon nanotube hybrids (CNTs) have attracted research interest due to their interfacial activity. CNTs can stabilize emulsions and foams and can be used as contrast agents or tracers in rock matrix. In addition, catalytic functionalities can be attached to the nanotubes making them delivery vehicles for catalyst into zones deep inside the reservoir.
Generating stable dispersion of CNTs in harsh reservoir conditions has been the main challenge for utilizing the tubes in in-situ reservoir applications. This is because the dispersed tubes tend to form aggregates that settle down in the presence of high ionic strength (high salinity) brines. In this work, stable dispersion of carbon nanotubes prepared in reservoir fluids is realized by successfully separating individual tubes using such additives as polymers and surfactants. For example, the CNTs would be well dispersed via sonication with highly polarizable polymer such as polyvinyl pyrrolidone (PVP) or Gum Arabic (GA). To mitigating their agglomeration, a secondary additive such as hydroxyethyl cellulose (HEC) polymer is also added to provide adequate steric repulsion for their propagation in porous media at high salinity brines. The nanotube dispersion generated using these dual polymer system is able to deliver successfully through both consolidated cores (200mD permeability of Berea sandstone) and sand pack experiments (4D permeability) with minimal retention at mimic reservoir conditions (65°C and brine compositions of 8% NaCl and 2% CaCl2). Results of the eluted nanoparticles indicate that greater than 80% recovery of injected concentration observed in both consolidated and non-consolidated porous media. Small adsorbed amount of nanotubes is capable of saturating the adsorption sites inside porous media resulting in complete propagation of subsequent injections; this is corroborated by nanotube concentrations approaching 100% of the injected concentration after few pore volumes of injection.
Experiments also demonstrated that in the presence of residual oil inside crushed Berea sandstone sand columns, the extent of nanotubes adsorption to the oil/water interface is a function of the level of oil saturation.
This work is providing insight about the full potential of using carbon nanotubes in oilfield development applications.
The incompatibility of cement and shale and the subsequent failure of primary cementing jobs is a very significant concern in the oil & gas industry. On wells ranging from hydraulically fractured shale land wells to deepwater wells, this incompatibility leads to an increased risk in failing to isolate zones, which could possibly present a well control hazard and can lead to sustained casing pressure. The cement-shale interface presents a weak link that often becomes compromised by the loads incurred either during drilling, completion/stimulation or production phases.
To formulate cements for effective zonal isolation, it is crucial to evaluate the bond strength of the cement-shale interface. Although several studies have focused on the interactions between cement and sandstone, very few studies have addressed the bonding behavior of cement with shale. The conventional push-out test protocol used to measure cement-to-sandstone shear bond strength has proven to be difficult to apply to shale due to its laminated and/or brittle nature that complicates sample preparation and can lead to shale or cement matrix failure instead of failure at the interface. In this paper, we present a novel, simple and versatile laboratory test procedure to measure the shear bond strength between cement and shale.
The new procedure was used to develop cement formulations to improve the cement-to-shale bond. Various types of surfactants were added to cement slurry to evaluate their effects on cement bonding property. Our results indicate that bond strength of cement with shale can be enhanced by incorporating particular surfactants in cement slurries.
The success of matrix acidizing treatments, whether in carbonate or sandstone formations, depends significantly on the selected acid or acid mixtures. Limitations are applied on all existing acidizing fluids including hydrochloric acid and organic acids. These limitations include: low dissolving power, product solubility, stability, biodegradability, and the inevitable cost of additives necessary to mitigate corrosion problems. This work proposes a new mixture of lactic and gluconic acids which offers favorable technical characteristics and excellent health and environmental profile. After formulated, the acid was tested and optimized for the maximum calcium product solubility. The new acid is noncorrosive, nonvolatile, nontoxic, and can be used at a higher pH with significant sequestering power, and it is readily biodegradable (98 % at 48 h). The solubility of calcium salt of this acid is approximately 400g/l (compared with 300 g/l for calcium acetate, 166 g/l for calcium formate, and 79 g/l for calcium lactate). Interestingly, sodium salt of the acid mixture was reported as a corrosion inhibitor for steel alloys.
The objectives of the work are to: (1) examine the dissolving capacity and reactivity of the proposed acid through solubility and reaction rate studies over a temperature range of 80-300°F using the rotating disk reactor, (2) investigate the effectiveness of the new acid to create dominant wormholes and determine the optimum injection conditions in calcite cores.
Acid capacity reactions with Pink Desert limestone powder showed that 1:1 of 1 M lactic:gluconic acid mixtures was the optimum molar ratio that resulted in dissolving the maximum calcium amount for the reaction at 25°C and 500 rpm, while the reaction of lactic acid alone at the same acid concentration showed a white precipitation of calcium lactate in the collected samples. Reaction rate experiments on the rotating disk reactor showed that the rate of reaction of the proposed acid at 1:1 molar ratio is confined by the reaction rate of the two individual acids (lactic and gluconic acids). However, the reaction of lactic acids resulted in white precipitates on the surface of the rock disks used in the experiments. Coreflood study showed the ability of the new acid mixture to stimulate Indiana limestone cores at various injection rates, acid concentrations, and over temperature range between 150 and 300°F. The results also confirmed that 1:1 molar ratio of the two acids is the optimum for the minimum acid pore volume required to breakthrough. 20 wt% of the proposed acid was the optimum acid concentration associated with the minimum acid pore volume. Above this concentration, little impact was noted and the reduction in the pore volume leveled off.