Chemical EOR is an increasingly employed approach used to enhance oil recovery by combining changes in fluids mobility, macroscopic sweep, interfacial tension, etc. to essentially improve, or extend the economic life of a water flood. It includes flooding with polymer, surfactant, alkaline/surfactant, alkaline-surfactant-polymer (ASP), CO2 and / or other miscible gases which is often combined with waterflood (
The paper evaluates the main chemical changes that occur in the system for each EOR approach –– and shows how these changes, including in situ reservoir reactions and the stability/instability of the EOR packages themselves can exacerbate a range of PC-related challenges especially when considering the likely production of up to three different fluids: formation water, the EOR flood medium and any previous flood water from previous secondary recovery
The paper includes modelling results, laboratory results to validate model predictions as well as examples from field case studies to illustrate the impact of the chemical changes referred to above. Specific highlights include the impact of the use of either high- or low-pH EOR fluids on scale control, corrosion control and asphaltenes control; for scale it examines both inhibitor performance
The overall conclusion is that chemical EOR can have significant impact on PC and that these should not just be considered at the design stage and not just for the injection system but also to take into account the impact these may have on production wells following breakthrough of flood waters, showing that essentially each new or exacerbated PC issues can be predicted or at least anticipated with the required degree of confidence before implementation of EOR.
Raney, Kirk (Locus Bio-Energy Solutions, LLC) | Alibek, Ken (Locus Bio-Energy Solutions, LLC) | Shumway, Martin (Locus Bio-Energy Solutions, LLC) | Karathur, Karthik (Locus Bio-Energy Solutions, LLC) | Stanislav, Terry (Locus Bio-Energy Solutions, LLC) | West, Gary (Locus Bio-Energy Solutions, LLC) | Jacobs, Marc (Penneco Oil Company)
New biochemically-derived products for the removal of paraffin wax from oil wells do not require additional capex nor heat and do not utilize bacteria. They contain inactivated microbial cells, biosurfactants and biosolvents, and other components harvested as microbial byproducts that emulsify and dissolve paraffin from rock pores and from the well surfaces over wide temperature, salinity, depth, and pH ranges. Additionally, they increase oil recovery by remediating near-wellbore formation damage, reducing interfacial tension, altering rock surfaces and changing their wettability, and reducing oil viscosity. The product application is environmentally superior to well treatments using hot oil/water and aromatic solvents and is economical due to low capital and operating costs required for product synthesis. Specifically, product preparation is achieved using a modular fermentation system that is installed near the points of application. This insures highly efficient and low-cost production and logistics, as well as reducing time from generation to application which maximizes potency. With sufficient space, water, and electricity, the initial manufacture of the dispersal products can occur within a few weeks.
The treatment products utilized were initially developed and tested in laboratory studies, which showed that dispersion rates of the relevant paraffin samples were comparable to those achieved with toluene. The paraffin dispersal products exhibit a very high level of efficacy and safety when deployed in the Appalachian and Permian Basins. The potency of these products has led to outstanding paraffin removal results as indicated by reduced well failures in both vertical and horizontal wells and by visual observation of sucker rods removed from the wells. In addition, tank sludge and wax deposits in pipelines can be removed through either residual product flowing from the well or through direct application. Growth of detrimental bacteria and formation of biofilms are inhibited by the product application thereby reducing corrosion risk.
Specifically, details of an almost two-year 70-well study in the Appalachian Basin are reported in which no well failures were observed due to paraffin buildup and 95% of the wells exhibited an enhanced oil recovery effect during the paraffin remediation treatments. This resulted in an approximate 50% average increase in sustained production rate over baseline. Analysis of the results forecasts a substantial increase in future production, thereby significantly enhancing the value of the producing wells. Importantly, longer times between required treatments and the increased recovery rates have transformed the paraffin maintenance program into a documented revenue generator for the operator.
Models for steam or hot-water injection into a fractured diatomite or shale reservoir are developed from existing analytic models of energy transport and countercurrent imbibition.
Radial convective heat flow through a horizontal fracture system is modeled with conductive heat flow into the low-permeability matrix. The flow geometry approximates hot-fluid injection into a five-spot pattern. Recovery mechanisms accounted for in the models include capillary imbibition and thermal expansion. Temperature dependence of viscosity and interfacial tension (IFT) are included in the imbibition estimate. Laboratory data are needed to quantify the magnitude of the imbibition mechanism, which is usually the primary contributor to oil recovery. Reservoir properties representative of either the Belridge Diatomite or the Antelope Shale, two giant fractured oil reservoirs, are used for the model forecasts. Currently, however, only temperature-dependent imbibition data for diatomite reservoirs are available.
The steamflood model has been partially validated against a large-scale project in the Belridge Diatomite. By use of public-domain information, a reasonable comparison was obtained between the model and the field project during a 4-year injection period. Comparison with conventional thermal simulation was also performed, and it indicated reasonable agreement with the steamflood analytical model.
The models have been used to determine the key factors determining the success of thermal recovery in fractured, low-permeability reservoirs. Steam injection is shown to be superior to hot-water injection in heating the matrix. Key factors enhancing recovery include reduced fracture spacing, increased matrix permeability, and increased injection temperature. Model results indicate that steamflood recoveries of more than 40% of the original oil in place (OOIP) may be achieved by injection in diatomite containing light oil. Application to diatomites containing heavy oil also shows good performance. Successful application in diatomite reservoirs is forecast to be possible in the current low oil-price environment. Economic application in fractured shales, assuming similar imbibition behavior as in diatomites, would require a higher oil price because of the higher well costs and lower oil content relative to diatomite projects.
Because of the significant volumes of remaining oil in place (OIP) in both the diatomite and shale reservoirs, the application of thermal enhanced oil recovery (EOR) to these resources represents the logical next step in steamflood development.
Nabet, Medhat (Basrah Gas Company) | Noori, Sabah (Basrah Gas Company) | Salman, Muhammad (Basrah Gas Company) | Abidi, Syed (Basrah Gas Company) | Orrock, Steve (Basrah Gas Company) | Bonner, Chris (Basrah Gas Company) | Kloeck, Gert (Basrah Gas Company) | Everdingen, Huib Van (Basrah Gas Company)
Umm Qasr storage and marine terminals are strategic assets for the gas investments in Iraq. Together they are the only Natural Gas Liquids Export Hub in Iraq and a key enabler to increase the capture of Iraq's flared gas. Basrah Gas Company (BGC) started operating and developing Umm Qasr storage and marine terminals since its commencement of operations in May 2013 with a development plan to increase capture of flared gas and turn Iraq into net exporter of LPG. The development of Umm Qasr and the LPG export journey was phased into work streams that maximize the near-term and long-term value. Work Stream 1: Early Pressurized LPG Export Work Stream 2: High Pressure LPG Export Work Stream 3: Refrigerated Export The transition from pressurized LPG export to Refrigerated Export and the rehabilitation of Umm Qasr Marine Terminal jetties to comply with international safety and maritime standards is one of the most impactful projects in Southern Iraq. The project will provide the enabling infrastructure to increase export of Iraqi refrigerated propane and Butane positioning Iraq as one of the major players in the international LPG export market and diversifying its export revenues, besides providing impetus for further development of upstream gas capture and developments, and mid stream gas processing and utilization projects not just in south, but also in Norther Iraq using the already existing LPG grid network. The refrigerated export scope comprises the rehabilitation of refrigeration trains that chills propane (C3) and Butane (C4) to 43 deg and 5 deg. C respectively turning them into liquids at atmospheric pressure, along with associated propane and butane cryogenic Tanks, cryogenic product pipelines between storage and marine terminals, rehabilitation and modernization of marine jetties 1 and 2 including dredging of more than 1 million cbm of soil, automation, safety and integrity upgrades with aim to cater for Very Large LPG Gas Carriers (VLGC) and Medium Range class Product (Naphta) tankers of 50,000 Tons DWT This paper pronounces the challenges, approach and impact of reviving Umm Qasr Storage and Marine Terminals infrastructure that was built in 80s, only partially commissioned, suffered disrepair in successive wars and was extensively modified to suit the country's emergency import needs. 2 SPE-193326-MS
Gan, Quan (University of Aberdeen / Pennsylvania State University) | Fang, Yi (University of Texas / Pennsylvania State University) | Im, Kyungjae (Pennsylvania State University) | Elsworth, Derek (Pennsylvania State University)
Despite attempts to engineer viable deep reservoirs for the recovery of thermal energy at high enthalpy and mass flow rates - dating back to the 1970s - this goal has been surprising elusive. The record is replete with failed attempts, examples on life support and some successes. The key difficulties are in (i) accessing the reservoir inexpensively and reliably at depth, (ii) in penetrating sufficiently far through the reservoir, and (iii) in stimulating the reservoir in a controlled manner to transform permeability from microDarcy to higher than milliDarcy levels with broad and uniform fluid sweep and (iv) to create and retain adequate fluid throughput and heat transfer area throughout the project lifetime. We discuss key controls on permeability evolution in such complex systems where thermo-hydro-mechanical-chemical and potentially biological (THMC-B) effects and feedbacks are particularly strong. At short-timescales of relevance, permeability is driven principally by deformations - in turn resulting from changes in total stresses, fluid pressure or thermal and chemical effects. We explain features of reservoir evolution with respect to both stable and unstable deformation, the potential for injection-induced seismicity and its impact on both reservoir performance and in interrogating the evolving state of the reservoir.
The estimated thermal resource in the upper 5 km of crust below the US is of the order of 107 EJ. This compares favorably both with the hydrothermal resource at a mere 104 EJ and to the annual energy budget for the US, at ∼100 EJ/year. Recovering even a fraction of this baseload resource would contribute significantly to a new low carbon energy economy.
The intrinsic goal of recovering thermal energy from the shallow crust (∼5 km for Engineered Geothermal Systems) requires that high-fluid-throughput and thermally-long-lived geothermal reservoirs may be universally engineered and developed, at will, and at any geographic location. High-fluid-throughput in traditional basement rocks requires that reservoir permeabilities at depth (∼5 km) must be elevated from the microDarcy to the milliDarcy range - this avoids untenable pumping costs and avoids inadvertently fracturing the reservoir by extreme fluid overpressuring of the heat-exchange fluid. Although fracturing would appear desirable in developing conduits with high-fluid-throughput, it typically violates the second tenet of a desired long thermal life, which
requires that high heat-transfer area is maintained concurrent with high flow rates. This is only feasible if fluid circulation in the reservoir has a broad and even sweep through media with a short thermal diffusion length (small fracture spacing) thus avoiding short-circuiting and damaging feedbacks of thermal permeability enhancement.
Some of the most prolific oil fields in the world have been produced or are operating under complete water drives through all or substantial parts of their producing lives. The most celebrated example is, of course, the East Texas field. Others are the fault-line fields in Texas' --Powell, Wortham, Currie, Richland, and Mexia--the Frio reservoir at Thompson in Texas, many of the fields in Kansas, and some of the Arbuckle Limestone fields in Arkansas. Many of the more recently developed fields in Mississippi, as Pickens, Tinsley, Eucutta, and Heidelberg, produce such highly tmdersaturated crudes that they can develop no gas-drive components until the pressures have fallen to small fractions (of the order of M to M) of their initial reservoir pressures.
This paper documents the findings based on interpretation of the geochemical composition of oils from the Bualuang Field located in the western Gulf of Thailand, and how these oils compare with other oils and potential source rocks in the region. The Bualuang Field is located in Block B8/38, on the eastern flank of one of a series of north-south trending, Tertiary half-grabens which are part of the greater Western Basin.
Eight oil samples from five wells on the Bualuang Field were analysed using gas chromatography (GC), gas chromatography-mass spectroscopy (GC-MS) and carbon isotopic techniques. Selected samples were further analysed by GC-MS-MS. This paper provides a review of these analyses, presenting key geochemical evidence for the likely age and facies of the source of this oil. A comparison is then made between the Bualuang Field oils and other oils from the immediate surrounding area as well as more regionally. In addition, the oils are considered against potential Mesozoic source rocks observed in peninsular Thailand.
The molecular and isotopic analysis of the Bualuang oils show strong similarity, and origin from a carbonate facies (probably marly) as indicated by dominance of C29 hopane over C30 hopane, presence of significant C30 30-norhopane, abundance of C24 tetracyclic terpane and low amounts of diasteranes. Furthermore, the oils are believed to have a marine origin due to the presence of C30 steranes (confirmed by GC-MS-MS), a C26/C25 tricyclic terpane ratio in excess of 1, and the stable carbon isotopic composition. The source of the Bualuang oil is considered older than Tertiary because of the absence of oleanane (typically significant in Tertiary oils), the dominance of 27-norcholestanes (24-norcholestane ratio
Importantly this paper provides strong, albeit indirect, geochemical evidence for an additional oil-prone source to consider within the western Gulf of Thailand, which is believed to be Mesozoic in age. One of the key exploration challenges is related to identifying the presence and extent of such a Pre-Tertiary source on seismic data.
Plunger lift is a well-known artificial lift technique originally developed for the de-liquefaction of gas wells. However its use has been extended to include high Gas – Oil Ratio (GOR) oil wells, those with low or no production due to paraffin and scale deposits and wells with high or fluctuating sales line pressures. It is an intermittent production technique that utilizes reservoir energy stored in the gas phase to lift oil from the bottom of the well to surface via the vertical cyclic action of a "pigging" device within the tubing. This action enhances the production performance of liquid loaded wells.
In this study, plunger lift systems on two wells were evaluated to determine well performance and to optimize production rates if plunger lift systems were to be installed on other wells. Casing and tubing pressure trends were used to identify operational deficiencies and causes. Vogel's model was used to model the inflow performance relationship using bottom-hole pressure data. The Foss and Gaul model for plunger lift operation was used to determine production rates and gas requirement for each well in order to optimize well performance. The mode of operation with the current settings (long after-flow periods and over-estimation of plunger fall back time) is representative of intermittent lift with the assistance of a plunger rather than gas assisted plunger lift operation. The GOR for both wells are too low for efficient operation and a model of the current settings indicates that a gas injection rate of 450 MSCF/D is required to obtain an optimum oil production rate of 103 bopd. These plunger lift systems also prevent paraffin accumulations in the production tubing of these two wells.
New plunger lift operating variables such as casing valve opening and closing time, gas injection rate, after flow time, plunger rise velocity and fallback time, flow-line motor valve cycle time and number of cycles per day were modeled to obtain an optimum oil production rate. The results showed that a gas injection rate of 173 MSCF/D is required to obtain an oil production rate of 195 BOPD for a plunger rise velocity between 800 to 1000 ft/min. For these new settings the gas requirement was reduced by 61 % and the oil production increased by 89 %. These results indicate that the modification of the operating variables can effectively optimize gas assisted plunger lift systems that are installed in the oil wells producing from the Cruse Formation in the Main Soldado field offshore the Southwest coast of Trinidad.
Simser, B. (Sudbury Integrated Nickel Operations, A Glencore Company) | Deredin, R. (Sudbury Integrated Nickel Operations, A Glencore Company) | Jalbout, A. (Sudbury Integrated Nickel Operations, A Glencore Company) | Butler, T. (Engineering Seismology Group (ESG), Canada Inc.)
Case studies are presented from Glencores’ Fraser Copper, Fraser Morgan and Nickel Rim South Mines showing how microseismic monitoring data can be used as an aid to rock mechanics decision making and design verification. At Nickel Rim South and Fraser Morgan, examples of how recorded development blasts can be used to quickly evaluate source location accuracy and infer the state of rockmass conditions are given. Examples are given as to how network sensitivity can enhance the understanding of the rockmass response to mining are also presented and a case is made for 3D velocity models and recognizing the impact of waveform attenuation from raypath effects, and yielded rockmass conditions. At Fraser Copper, a case history shows how seismic information was useful for evaluating the performance of a successful longhole destress blast that was performed when face-bursting was encountered during a planned underhand extraction of a highly stressed remnant.
Glencore’s Sudbury Integrated Nickel Operations includes three underground operations, the Nickel Rim South Mine, Fraser Copper Mine, and Fraser Morgan Mine, all located near Sudbury, Ontario, Canada (Figure 1).
Fraser Morgan is a nickel deposit accessed via the Fraser Copper Mine infrastructure. Close to 2 million tonnes per year of ore are mined underground from all operations, with Nickel Rim South providing the majority of the material at 1.3 Mt/year.
All three operations are hard rock mines, with excellent rockmass quality. The depth of mining is sufficient to develop pervasive stress fracturing around most openings (Figure 2).
Petrobras and partners have been developing Brazilian Santos Basin Pre-Salt ultra-deepwater areas through the use of Floating Production Storage and Offloading Units (FPSOs), equipped with topside facilities designed to receive produced fluids and process them to generate end streams to export and injection.
The large hydrocarbon volumes in Santos Basin Pre-Salt areas, which have been successively confirmed by the results of exploratory and productions wells, have encouraged Petrobras and partners to choose an aggressive development strategy over a more conventional one. Based on this decision, FPSOs were chosen, mainly due to crude oil storage capability thus not requiring the construction of long-length oil pipelines, and also because of other characteristics that allow a short term completion with economic advantages. Therefore, the topside process plant conceptual design had to deal with uncertainties in the reservoir fluid compositions and production profiles. This means a wide range of CO2 and H2S contents, oil API gravity, flow rates and arriving fluid pressures and temperatures, in order to guarantee an adequate nominal capacity and turndown, and also the proper performance within the established design cases.
The main purpose of the topside facilities is to gather and treat the produced fluids to be sent ashore. The treated oil is routed to cargo tanks, the produced water is treated and discharged overboard, an dthe bulk treated gas stream is exported through a gas pipeline network, which allows to send the stream to three different gas processing sites onshore. The separated CO2-rich stream is injected back to the reservoir.
Besides the production units specially designed for Santos Basin Pre-Salt features, some Pre-Salt reservoirs from Campos Basin have been also being produced, by connecting new wells to existing production units. The main approaches regarding these units and its production in Campos Basin Pre-Salt are also part of the scope of this paper.
As a result of these different strategies and due to the daily efforts to overcome the forementioned challenges, more than six hundred thousand barrels per day of crude oil, as a monthly average, have been produced in Brazilian Pre-Salt areas, after only eight years since the early developments of the area.