In need of an exploration boost, Norway doled out a record 83 production licenses in mature areas of the Norwegian Continental Shelf to 33 firms. This paper aims to develop new and improved empirical viscosity correlations through available field measurements on the Norwegian Continental Shelf (NCS). When a new horizontal well in Asia was incapable of unassisted flow, coiled tubing (CT) was selected for the perforation and stimulation intervention. Mechanical isolation was required to ensure that the stimulation fluids entered only the new zones. The company’s 31 licenses highlight a record-high total awarded during the latest APA round, which is aimed at developing mature areas of the NCS.
The decision to ramp down production on the Aspen project comes months after the Alberta provincial government imposed production cuts to handle pipeline bottlenecks. Aspen is projected to produce 75,000 BOPD upon startup. Canada will become the world’s fifth-largest producer of crude oil in 2017. The solvent-assisted-SAGD poses the largest advancement in production techniques in the oil sands, and if scaled up, could further reduce extraction costs. To support subsea processing of heavy crudes, an inline electrocoalescer was tested for separation of water droplets dispersed in the crude oil.
The development and upgrade of mature facilities is ultimately driven by the significant shift in the composition of the arrival fluids, mainly the increasing water cut and solids production. For many projects, asphaltene management plans are a matter of remediation or prevention. In the past decade, models have been developed to predict how asphaltene particles will behave in oil—the conditions under which precipitation and agglomeration occur. The SPE Separations Technology Technical Section (STTS) will hold a three-webinar series on the theme of gas scrubbing technology this year with the first to be held on 3 March. Where will the next big idea come from?
It is no secret that drilling fluid is crucial in drilling operations. The main function of drilling fluids is to transport drill cuttings from the bottom of the hole up to the surface. Drill cuttings then will be separated on the surface before being recycled back for further drilling. Drilling fluid is subjected to extreme pressure and temperature, and its properties such as viscosity are affected strongly by pressure and temperature. Always recorded but almost never used, the water hammer signal could offer completions engineers another set of insightful data if petroleum engineers can crack its code.
The use of high viscosity friction reducers (HVFR) as alternatives to guar-based fluids to improve proppant transport and lessen formation damage has increased rapidly. While several product options are available, the criteria for selection of a product has focused on viscosity at 300 RPM (511s-1) that meets or exceeds that of linear gel fluids. However, there has been limited data available on what the target viscosity should be, how it influences the fluid's ability to transport sand, and the potential for damage to proppant conductivity. This study presents methodology used to screen HVFR's and results on product performance, which identified a need for alternative specifications to viscosity to achieve maximum performance.
The proppant transport capacity in dynamic conditions was evaluated for twenty-eight commercially available friction reducers and HVFR's in field waters which could have up to 40,000 TDS. A slot flow apparatus was used to mimic fluid flow through a fracture under different shear and flow rate conditions. Viscosity and elasticity measurements were also obtained using an advanced rotational rheometer. For comparison, linear gel and crosslinked guar fluid were also evaluated.
While viscosity at 300 RPM (511s-1) and more recently high viscosity at lower shear rates, have been used for selection of HVFR's, these parameters alone do not indicate proppant carrying capacity. The authors did not find a correlation between higher viscosity and better proppant transport, rather they propose that too high a viscosity can negatively impact transport. The results provided insight into the effect of flow rate on proppant transport, with some HVFR's that exhibited higher viscosities at low shear, losing their transport capacity at the same low shear. Elasticity testing of those same products suggested that HVFR's have a critical elasticity range at which they will provide optimal performance. Polymer residuals were also evaluated on proppant post-test and compared to traditional linear gels and crosslinked fluids. Results suggested potential for damage if HVFR's are used without breakers. Different viscosity targets should be set when selecting a HVFR and coupled with other testing criteria such as elasticity and dynamic proppant transport.
This paper provides insight into the need for development of standardized test criteria for HVFR selection. Further testing and screening of HVFR's will help increase the understanding of key factors influencing sand transport and their effect on proppant pack conductivity.
Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift.
Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time.
The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.
The primary purpose of using traditional friction reducers in stimulation treatments is to overcome the tubular drag while pumping at high flow rates. Hydraulic fracturing is the main technology used to produce hydrocarbon from extremely low permeability rock. Even though slickwater (water fracturing with few chemical additives) used to be one of the most common fracturing fluids, several concerns are still associated with its use, including usage of freshwater, high-cost operation, and environmental issues. Therefore, current practice in hydraulic fracturing is to use alternative fluid systems that are cost effective and have less environmental impact, such as fluids which utilize high viscosity friction reducers (HVFRs), which typically are high molecular weight polyacrylamides. This paper carefully reviews and summarizes over 40 published papers, including experimental work, field case studies, and simulation work. This work summarizes the most recent improvements of using HVFR’s, including capability of carrying proppant, reducing water and chemical requirements, its compatibility with produced water, and environmental benefits in hydraulic fracturing treatments. A further goal is to gain insight into the effective design of HVFR based fluid systems.
The findings of this study are analyzed from over 26 field case studies of many unconventional reservoirs. In comparing to the traditional hydraulic fracture fluids system, the paper summaries many potential advantages offered by HVFR fluids, including: superior proppant transport capability, almost 100% retained conductivity, cost reduction, minimizing chemicals usage by 50%, less operating equipment on location, reducing water consumption by 30%, and fewer environmental concerns. The study also reported that the common HVFR concentration used was 4gpt. HVFRs were used in the field at temperature ranges from 120°F to 340°F. Finally, this work addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.
The novel nanomaterial composition described in this paper has been designed to treat moderate to severe losses. The nanomaterial composition comprises an environmentally friendly nanoparticle based dispersion and a chemical activator. The design is based on a delayed activation chemistry to gel up a nanoparticle based dispersion.
Three different types of nanoparticles were used in the study to develop the novel loss circulation material. Two different types of negatively charged nanoparticle based dispersion and one positively charged nanoparticle based dispersion were used in the study. An inorganic activator has been used for the study. The effect of this inorganic activator on the gelation properties of the nanoparticle based dispersion was investigated. The gelling times were evaluated at different temperatures up to 300°F. The effect of activator concentration on the gelling time of the new composition has also been studied. The effectiveness of the newly developed composition as a loss circulation treatment was also evaluated by performing permeability plugging tests to test the plugging capacity of this novel system.
The novel nanomaterial composition is designed so as to have a controllable gelation time under a variety of downhole conditions to allow accurate placement of the treatment fluid inside the wellbore without premature setting of the fluid. It was shown that the gelation time of the treatment composition could be controlled by adjusting the concentration of the activator. The system is designed so as to give a predictable and controllable pumping time, ranging from a few minutes to several hours at over a wide range of temperatures. This is an important advantage as it allows the loss circulation composition to remain pumpable for sufficient time for placement and develops the network structure that leads to gelation, over a predictable period of time. The set gel, which appears as a crystalline solid, could remain homogenous and stay in place thereby preventing loss circulation.
The recent and rapid success of using high viscosity friction reducers (HVFRs) in hydraulic fracturing treatments is due to several advantages over other fracture fluids (e.g. linear gel), which include better proppant carrying capability, induce more complex fracture system network with higher fracture length, and overall lower costs due to fewer chemicals and less equipment on location. However, some concerns remain, like how HVFRs rheological properties can have impact on proppant transport into fractures. The objective of this study is to provide a comprehensive understanding of the influence the rheological characterization of HVFRs have on proppant static settling velocity within hydraulic fracturing process. To address these concerns, comprehensive rheological tests including viscosity profile, elasticity profile, and thermal stability were conducted for both HVFR and linear gel. In the steady shear-viscosity measurement, viscosity behavior versus a wide range of shear rates was studied. Moreover, the influence of elasticity was examined by performing oscillatory-shear tests over the range of frequencies. Normal stress was the other elasticity factor examined to evaluate elastic properties. Also, the Weissenberg number was calculated to determine the elastic to viscous forces. Lastly, quantitative and qualitative measurements were carried out to study proppant settling velocity in the fluids made from HVFRs and linear gel. The results of rheological measurement reveal that a lower concentration of HVFR-2 loading at 2gpt has approximately more than 8 times the viscosity of linear gel loading at 20ppt. Elastic measurement exposes that generally HVFRs have a much higher relaxation time compared to linear gel. Interestingly, the normal stress N1 of HVFR-2, 2gpt was over 3 times that of linear gel loading 20ppt. This could conclude that linear gel fracture fluids have weak elastic characterization compared to HVFR. The results also concluded that at 80 C° linear gel has a weak thermal stability while HVFR-2 loses its properties only slightly with increasing temperature. HVFR-2 showed better proppant settling velocity relative to guar-based fluids. The reduction on proppant settling velocity exceed 75% when HVFR-2 loading at 2gpt was used compared to 20ppt of linear gel. Even though much work was performed to understand the proppant settling velocity, not much experimental work has investigated the HVFR behavior on the static proppant settling velocity measurements. This paper will provide a better understanding of the distinct changes of the mechanical characterization on the HVFRs which could be used as guidance for fracture engineers to design and select better high viscous friction reducers.
Zagitov, Robert (Cairn Oil & Gas, Vedanta Ltd) | Venkat, Panneer Selvam (Cairn Oil & Gas, Vedanta Ltd) | Kothandan, Ravindranthan (Cairn Oil & Gas, Vedanta Ltd) | Senthur, Sundar (Cairn Oil & Gas, Vedanta Ltd) | Ramanathan, Sabarinathan (Cairn Oil & Gas, Vedanta Ltd)
Enhanced Oil Recovery is important stage of life cycle of a field and often it is implemented with challenges. In the chemical EOR, challenges and surprises are expected in production chemistry and production facilities operations. Partially hydrolyzed polyacrylamide used widely for controlling mobility ratio so that Operator is able to recover maximum possible oil. With complex water chemistry and rich in positively charged divalent ions, flooded polymer having negative charge interacts with divalent ions of produced water. Back produced sheared polymer interacts with divalent ions to form semi hard to hard scales poses challenges of the reliability of production facilities.
Other important limitations to be noted in CEOR phase are using production chemicals to control scale, emulsion and microbial treatment under Hydrogen Sulphide and waxy crude environment. This paper discusses about the requirement of preparedness and how to overcome challenges of EOR operations and in handling the back produced polymer in following areas: Selection of production chemicals to be compatible to polymer so that no or minimal degradation or loss of viscosity due to polarity of chemicals Performance of production chemicals in the presence of polymer Solids loading in production system Emulsion and produced water treatment Suitability of produced water treatment facilities Revised scaling and fouling control with back produced polymer with rich divalent ions present in produced water Strategizing chemical management system to suit polymer flood and polymerized back produced water treatment regime
Selection of production chemicals to be compatible to polymer so that no or minimal degradation or loss of viscosity due to polarity of chemicals
Performance of production chemicals in the presence of polymer
Solids loading in production system Emulsion and produced water treatment
Suitability of produced water treatment facilities Revised scaling and fouling control with back produced polymer with rich divalent ions present in produced water
Strategizing chemical management system to suit polymer flood and polymerized back produced water treatment regime