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Because of inherent complexities, understanding the characteristics of perforations in downhole environments is a significant challenge. Perforation-flow laboratories have been used to provide insight into cleanup and productivity mechanisms around perforation tunnels. Erosion caused by fine solid particles presents one of the greatest threats to oil and gas flow assurance, consequently affecting material selection and wall-thickness design.
Because of inherent complexities, understanding the characteristics of perforations in downhole environments is a significant challenge. Perforation-flow laboratories have been used to provide insight into cleanup and productivity mechanisms around perforation tunnels. Completion engineers feel pressure to maximize production per acre and minimize the downsides of fracturing in tight spaces. Terry Palisch, talks about promoting knowledge sharing as part of JPT’s tech director report. An advisor at Schlumberger discusses the company’s work in examining the effect of perforations on hydraulic fracture initiation.
CHOPS is not suitable for all heavy unconsolidated sandstone (UCSS) reservoirs. Recovery factors greater than 20% of OOIP are unusual; values of 10 to 16% are more common. However, combining CHOPS with other production technologies may increase ultimate recovery factors. Through yield, dilation and liquefaction, and perhaps through channeling, CHOPS creates a large region of greatly enhanced permeability. Is it possible to exploit this with other technologies?
In the last two decades, the oil industry has dedicated considerable resources and efforts to developing chemical treatments to remove near-wellbore damage. The two main lines of work include formulations with multiple components (either solvent-based or water-based) and multifunctional microemulsion technologies that combine solvent-based and water-based treatments in a single-phase fluid. Microemulsion technology has been applied in onshore and offshore wells, open-hole and cased-hole wells, newly drilled wells, and mature fields with issues of declining production. Various formulations are currently used for near-wellbore remediation in the oil industry. This paper reviews publications relevant to near-wellbore remediation, in particular those that discuss microemulsion treatments. The review covers types of near-wellbore damage (emulsions, drilling fluids damage, sludge, scales, wettability alteration, paraffins and asphaltenes deposits) and the results of microemulsion evaluation and near-wellbore damage treatments. The paper also presents a suite of laboratory tests for microemulsion evaluation and selection for nearwellbore remediation.
Two drilling rigs sit in Eddy County, New Mexico, in September 2019. In a matter of months, serious doubts have been cast over the short- and medium-term future of oil and gas production in the area. The COVID-19 disaster and a catastrophic fall in oil prices could leave the state on the hook for billions in environmental cleanup costs if oil and gas companies go bankrupt during the health crisis, New Mexico's top land official says. The crash in the oil and gas market is fueling long-standing concern from State Land Commissioner Stephanie Garcia Richard and environmental groups that bonding requirements for oil and gas companies are nowhere near enough. "We never dreamed that we would be in this position," she said.
Pfeiffer, Thomas (Schlumberger) | Sarili, Mahmut (Schlumberger) | Wang, Cong (Schlumberger) | Naito, Koichi (Schlumberger) | Morikami, Yoko (Schlumberger) | Chen, Hua (Schlumberger) | Shabibi, Hamed (Petroleum Development Oman) | Frese, Daniela (Petroleum Development Oman)
For every barrel of oil, about three to four barrels of water is produced. Water is part of every operation in upstream oil and gas: we produce it, we process it, we inject it. It affects our reserves because it may drive or sweep the oil out of the pores. It is a source of corrosion and scaling in pipe and in the reservoir. Measuring formation water resistivity (Rw) goes beyond using it as the basis of petrophysical well log interpretation. It is the key to telling different waters apart for taking the most representative samples.
We introduce a calibrated induction-based water resistivity measurement sensor, which is configured to accurately measure Rw in the flowline of a formation testing tool. The induction-based operating principle of the sensor eliminates the use of electrodes and the associated fouling of the measurement due to coating or accumulation of particles on the electrodes. Instead, the sensor induces an electric current through a nonconductive, neutrally wetting flowline tube that is proportional to the conductivity of the fluid column within the tube. The resulting current at the receiver coil is then converted into resistivity.
A case study presents data from a focused water-sampling station in a transition zone in a well drilled with water-based mud (WBM). The resistivity contrast between the mud filtrate and the formation water is low and mobile oil mixes with the formation water and mud filtrate. Despite these difficult conditions, the downhole measurement clearly shows the cleanup progress in real time and compares well with the surface measurements of the water samples. The ability to differentiate formation water from WBM filtrate with low resistivity contrast in the presence of oil places the station depth in the transition zone and enables accurate interpretation of contacts, saturation, and ultimately hydrocarbon in place.
The sensor package is suitable for use up to 200-degC temperature and 35,000-psi pressure. The sensor can measure a wide range of resistivity, from 0.01 to 65 ohm.m. Measurements performed on known fluids prove its high accuracy of ±5% or less for resistivity below 10 ohm.m at a resolution of 0.001 ohm.m. The design eliminates any dead volume and all flowline fluid passes through the sensor. The sensor tube is smoothly flushable for fast dynamic response in multiphase slug flow.
This paper also discusses optimal sensor placement and operational techniques to achieve best results in multiphase flow environments.
The accuracy and resolution of the resistivity measurement enables direct comparison of guard and sample flowlines during focused sampling and provides differentiation even when the contrast between filtrate and formation water is low. The results can serve as a direct Rw measurement, for example in an exploration scenario, as successfully shown in another PDO trial, or can be compared to other sources of Rw measurement or used to improve the accuracy of alternatives to the Archie equation, such as dielectric dispersion.
Nagar, Ankesh (Cairn Oil & Gas Vedanta Limited) | Davidson, Brett (Wavefront Technology Solutions Inc) | Srivastava, Preyas (Cairn Oil & Gas Vedanta Limited) | Verma, Nakul (Cairn Oil & Gas Vedanta Limited) | Shrivastava, Pranay (Cairn Oil & Gas Vedanta Limited) | Nekkanti, Satish Kumar (Cairn Oil & Gas Vedanta Limited) | Bohra, Avinash (Cairn Oil & Gas Vedanta Limited) | Vermani, Sanjeev (Cairn Oil & Gas Vedanta Limited)
Poor conformance is a major concern of Mangala, Bhagyam & Aishwarya (MBA) fields. The presence of high permeability streaks or thief layers between injection and production wells typically results in pre-mature water breakthrough, high water cut and deficient volumetric sweep. As a result, significant oil volumes in the reservoir may not be contacted by the injection fluid. Another concern is of low VRR (Voidage Replacement Ratio) in some of the layers due to reduced injectivity in those sands. Consequently, it has led to poor recovery from those sands. It is also a growing problem with the polymer deposition taking place in the wellbore particularly Mangala (undergoing full-field polymer flooding), leading to challenging wellbore cleanup operations.
Several methods have been used in the past, both mechanical and chemical to improve the treatment fluids during stimulation. In this paper, we introduce a novel placement technique for Conformance Improvement which is practical, effective and durable as well as another tool variant that helps cleanup challenging wellbore environments. Typically, prior to the tool allowing for pin-point placement, the adjustable nozzle tool is run to ensure that the perforation and wellbore is cleaned up thoroughly with help of advanced fluid dynamics. The dynamic injection modulation (hereinafter referred to as, "DIM") tool for pin-point stimulation placement improves the distribution of injected fluid in the reservoir matrix by the process of dispersion. The tool generates an energized fluid pulse that allows fluid to be diverted away from established fluid paths. The pressure pulse, as it travels dilates the pore spaces thus propagating the wave further into the reservoir. The pin-point accuracy of placements leads to treating of reservoir layers which are left untreated during conventional stimulation treatments where viscous fingering effects dominate. As a result, injection fluid would divert into uncontacted layers to improve sweep efficiency. The other advantage of the tool is the relatively easy integration of tool with existing infrastructure. The tool is easily run with coiled tubing ("CT") with only addition of an accumulator unit on surface.
This paper will document the tool physics, job design and Implementation technique for stimulation using Fluid Modulation tool as well enhanced well cleanup. Particular attention is paid to multiple injector and producer well stimulation case studies from these fields, the challenges faced, the solution proposed, and finally the results obtained. The results observed across the field with respect to injection performance is consistently greater than 75% over conventional methods used earlier. Also specifically, in scenarios of difficult fill cleanups, the advanced wellbore cleanup tool variant helped in multiple polymer and sand fill environment cleanouts over various wells over conventional methods of cleanup.
Laboratory formation damage testing is often used to assist in the selection of optimum drilling and completion fluids. Most test procedures (e.g. sand retention, return permeability) represent an attempt to simulate near wellbore conditions during well construction and production. Return permeability tests may enable comparison of fluids and drilling and completion methods, but by definition remain small scale simulations. The permeability changes measured may be indicative but are rarely used to predict the overall impact on well performance. What degree of permeability impairment is allowable? Some further interpretation is required, which cannot be provided for using classical nodal analysis or reservoir simulation methods.
The impact of formation damage on overall well productivity or injectivity depends on the magnitude and distribution of the damage. In order to translate laboratory data into quantitative well predictions it is necessary to represent the degree of restriction and the geometry of the damaged zone or zones in a full well simulation. Computational Fluid Dynamics (CFD) simulations provide a means to upscale suitable laboratory test data to predict impact on well performance. Different magnitudes of damage derived from laboratory test data can be simulated and the impact on overall well performance predicted for different completion environments.
Upscaling reveals that in some wells laboratory measured formation damage has little impact on well performance. Of course if damage is severe then impact is severe but it is critical to consider the well length, reservoir quality, drive mechanism and the well completion in order to fully understand the implications suggested by laboratory test data.
This paper demonstrates through several case histories applications of CFD modelling to upscaling of laboratory measured formation damage. Moreover, the real implications for well and completion design are revealed. The value of laboratory testing is quantified and some interesting challenges to conventional wisdom are proposed.
High viscosity friction reducer (HVFR) fracturing fluids are widely implemented for unconventional reservoir development. HVFR's are easy to apply and reduce chemical costs. The research objective of this paper is to measure polymer cleanup in both propped and unpropped fractures utilizing multiple methods. Additionally, the study will compare rheological measurements to proppant transport observations in brines using a large-scale slot flow device.
API conductivity cells determined pack damage over a range of proppant sizes, HVFR's, and temperatures. An extended length conductivity (ELC) apparatus was utilized for comparison with the API cell. Cleanup in unpropped fractures employed a core holder using fractured core plugs. HVFR rheological property measurements include low and high steady shear measurements, and oscillatory measurements used to determine elastic properties. Mix waters include fresh water, salt solutions, and a simulated field brine. Proppant transport in fresh and simulated field brine is evaluated in a 1 × 8 foot slot flow device. Proppant deposition rates are recorded using video cameras.
Propped fracture cleanup in the API cell and ELC apparatus is a function of proppant mesh size and HVFR type. As mesh size decreased, the potential for damage increased. Tests with 50/140 mesh proppants in the API cell in some cases showed significantly impaired regain conductivities as low as 65%. When compared to the ELC, API cell cleanups were in some cases significantly optimistic. Cleanup also varied greatly with HVFR product. Even with a low loading of HVFR of 1 gallon per thousand gallons of fluid (gpt) significant damage was sometimes noted. The tests of the unpropped fractures showed that very severe damage to unpropped fractures may occur. The presence of salts significantly and negatively affects HVFR rheological properties for most of the materials selected for this study. Viscosity at higher shear rates (10-511/sec) do not necessarily reflect HVFR performance at lower shear rates. In all tests, the rheological performance between different products exhibited a wide variation in properties, likely reflecting the potentially wide variation in chemical composition. Proppant transport testing validates the rheology measurements. The slot flow evaluations showed a significant loss of transport capability in brines. Commercial HVFR's are not equivalent and require laboratory performance evaluations.
The study demonstrated that the potential for significant damage to the proppant pack and reservoir is present with HVFR fluid systems. Even low salt concentrations significantly influence the HVFR rheological performance. Mix water compatibility must be a primary concern when selecting HVFR's. The results of this study provide useful information to engineers for selecting HVFR's and describes a methodology for evaluating damage potential, and proppant transport.
The design of solid management systems (SMS) facilities for offshore big bore HP/HT sour gas well cleanup is an industry challenge, mainly it is due to solid erosion (sand), potential high pressure H2S release, heat radiation from flare, SO2 exposure, vibration, noise, including risk of piping or facilities blockage, and corrosion (facility integrity) that might hinder safety, operability and environmental issues. The objective of this paper is to develop a solid handling management decision making process especially during early facilities development, identify the merit and limitation on each handling option. As methodology; firstly, technology screening and benchmarking will be performed. Then characterize solid composition, determine the expected solid/ mud flow back during well clean up, erosion and deposition study, hydraulic flow assurance and heat impact mapping. The next process is, develop a decision-making workflow based on solid handling option scenarios including offshore, onshore or a combination of them. Moreover, a hydrocyclone solid removal simulation is performed, and for the onshore application; flow loop experimental work is carried out on a small scale to prove the solid removal efficiency. Various flow rate, pressure and mud with different particle size and concentration from 7% to 15% with mixture of base fluid component are tested during the flow loop test. It is found that factors such as safety (operability), reservoir, well type, solid mud properties, the availability of infrastructure and footprint are playing important roles in the decision of well clean up strategy. Having offshore and onshore SMS will help solid management further robust. Based on the flow loop test study, solids management system with multi-stage separation process has a capability to remove more than 90% solids separation and in addition, differential pressure across stage need to be maintained.