Produced Fluid Composition Research Articles

Technology Focus: Oilfield Chemistry (September 2023)

Avid readers of recent technical literature in upstream energy can identify an upward trend in the frequency of studies that use large-data-set analysis to improve decision-making regarding production and operations. While big data and artificial intelligence had originally been fascinating concepts without wide examples of practical use, recent studies have showcased more practical uses of these methods of data analytics. The technical arena of oilfield chemistry, both that of the natural downhole environment and that of chemistry introduced downhole, provides a rich testing ground for advanced uses of data. Whereas early uses of data in the upstream chemical space included use of design of experimentation for vetting or developing new chemistries, today data analytics enables, for example, production allocation based on assessment of produced hydrocarbons. Featured studies showcase this type of application of data analytics to improve production assessment. One example reviewed various geochemical methods to allocate zonal contribution to production by analyzing produced fluid composition and decoupling the contributions of individual zones’ fluids. Another selection measured the carbon isotope signatures of gas from individual zones and used it to determine the thermal maturity of the gases from different reservoirs; this work has the potential for similar zonal allocation assessment of gas production. In its current maturity, machine learning also provides significant potential to improve our understanding and prediction of downhole chemical reactions. In another featured study, a geochemical data set of staggering proportions was populated with water composition data from many years and wells. Coupled with the equations that govern many downhole reactions to use machine learning, the presented tool allowed improved modeling and prediction of, for example, inorganic scaling behavior under downhole conditions. Recommended additional reading at OnePetro: www.onepetro.org. SPE 206091 Asphaltenes: Fundamental Principles to Oilfield Applications by Oliver Mullins, SLB, et al. SPE 211238 Detection and Monitoring of Corrosive Oilfield Microorganisms Through Novel Biomarker Technologies by Sven Lahme, ExxonMobil, et al. SPE 207340 Toward the Rational Design of Chemical Formulations for EOR From Carbonates: Molecular-Level Understanding of Carbonate Wettability and Its Reversal by Surfactants and Ions by Shixun Bai, University of Wyoming, et al.

Fluid phase behavior during multi-cycle injection and production of underground gas storage based on gas-condensate reservoirs with oil rim

Underground gas storage (UGS) plays an important role in energy supply and peak shaving of urban natural gas. Fluid phase behavior and mass transfer are complicated during multi-cycle injection and production of UGS especially based on gas-condensate reservoirs with oil rim, which will impact the fluid properties, gas-oil recovery factor and stability of UGS. This work innovatively develops an experimental approach to investigate the phase behavior during multi-cycle gas injection and production in a UGS based on gas-condensate reservoir with oil rim in Bohaiwan basin, China. The produced fluid composition, residual fluid properties and oil recovery factor are analyzed. Results indicated that the condensate oil recovery factor is only 24.12% and the oil rim influences condensate oil recovery factor during primary depletion. The oil recovery factors of individual cycles are 8.33%, 5.79%, 3.83%, 1.92% and 0.88%, respectively. The total condensate oil recovery is 20.75% after five cycles, indicating multi-cycle gas injection and production can effectively extract and evaporate oil phase especially in the first and second cycles. As the cycles increase, the composition difference between injected gas and oil rim becomes larger and the evaporation of oil rim by gas injection is weakened. The GOR of oil rim under the 24 MPa decrease from 190.5 to 162.5 m3/m3, indicating gas dissolving ability of oil rim decrease. The remaining oil saturation is 1.7% after five cycles, lower than the primary depletion (3.8%), indicating part of oil rim is also produced and the gas storage capacity is enhanced after multi-cycle injection and production. This work provides an approach to understand the phase behavior of UGS in condensate gas reservoirs with oil rim and is beneficial for the efficient operation of UGS.

Application of multicomponent sorption for diffusive transport in numerical simulation of tight reservoirs

One of the main challenges in modeling compositional transport in tight formations is to include the complex interaction of chemical species with rock surfaces. Such interactions result in compositional variations near the surfaces, which can significantly affect the compositional diffusive transport through tight pores.This paper presents the application of the Multicomponent Potential Theory of Adsorption (MPTA) for the fluid compositions in the central and near-wall sorbed layers subject to a wall chemical potential. The two-layer approximation of MPTA is implemented in the diffusive transport simulation that computes the mass transfer driven by fugacity gradient based on the dusty gas model for the central and sorbed layers of pores. This simulator uses a partially implicit formulation to solve the multiphase multicomponent mass transfer equations including the sorbed layer.The main novelty of this paper lies in the detailed analysis of the interplay between fluid components and rock surfaces, which became possible with the two-layer MPTA coupled with multicomponent diffusion. The diffusion simulation for a ternary case of methane, n-butane, and n-decane with the approximate MPTA shows that the sorption and capillary pressure can cause the compositional segregation between the central and sorbed layers. The segregation enhances the rates of methane injection and n-decane production in their counter-current diffusion. Methane (the lightest) is transported deep into the reservoir by diffusing through the central layer while n-decane (the heaviest) is diffused primarily through the sorbed layer. n-Butane (the intermediate) does not show preferential partitioning into either layer, resulting in relatively inefficient transport. In the absence of sorption and capillary pressure, the countercurrent diffusion occurs between methane (the lightest) and n-butane (the intermediate) while n-decane (the heaviest) remains nearly immobile. That is, whether the simulation considers the surface-fluid interactions can substantially affect the compositional transport (e.g., produced fluid composition) through tight porous media.The multicomponent Langmuir model is often used for computing the sorbed excess in micropores. However, results show that the Langmuir model becomes physically inconsistent at high pressures because it predicts a monotonically increasing function of pressure. The new approach developed in this research is sufficiently flexible and reasonably accurate for modeling multicomponent sorption at high pressures.

A new model simulating the development of gas condensate reservoirs

A new simulation model for the development of gas condensate reservoirs is introduced based on the influence that phase change, non-Darcy flow, and capillary pressure have on the production of gas condensates. The model predicts well performance, including bottom-hole pressure, oil/gas production rate, oil/gas recovery, gas–oil ratio, and the change in produced fluid composition. It also calculates dynamic characters, such as the change of pressure field and oil/gas saturation field during the development of gas condensate reservoirs. The model is applicable to different boundary conditions (both constant-pressure and sealed boundary) and different production modes (both constant-pressure and constant-volume production modes). Model validation attempted using numerical simulation results for sealed boundary conditions with constant-pressure production mode has shown a relatively good match, proving its validity. For constant-pressure boundary conditions with constant-volume production mode, four stages are defined according to the dynamic behavior of production performance in the development of gas condensate reservoirs.

METHODS OF PREPARATION AND PLUGGING MATERIALS APPLICATION TECHNOLOGY WHEN WATERPROOFING WORKS ON OIL WELLS PERFORMING

It is well known that many oil wells in the Volga-Ural Region have a high water cut degree. For the fields of PJSC TATNEFT, the average water cut is 70 %. Sometimes this value reaches 98 %! There are many reasons for this water cut level, including depreciation of the entire underground part of the well, non-compliance with technologies and the low-quality materials application in the well construction, operating rules violation. The resulting water flow between the aquifers and oil well horizons leads to a high water cut in the produced product and very often constitutes the greater amount in the produced fluid composition. To eliminate such crossflows, waterproofing works are carried out to separate the layers, which must be performed as efficiently as possible. Despite the large plugging compounds assortment and the variety application technologies, the success of waterproofing works remains low in many cases. The materials composing the plugging solutions do not always turn out to be of the required quality, and the work technologies, as a rule, are of a recommendatory nature and require amendments taking into account specific conditions. In this regard, a number of new materials, structure-forming agents and injection techniques have been proposed, which increase the waterproofing screen resistance to the formation waters breakthrough.

A Molecular Dynamics Study of Primary Production from Shale Organic Pores

Summary We created a model of mature kerogen saturated with a black oil. Our fluid model spans light, intermediate, and long alkane chains; and aromatics, asphaltenes, and resins. The maximum pore diameter of our kerogen model is 2.5 nm. The insertion of a microfracture in the system allows us to study fluid transport from kerogen to the microfracture, which is the rate-limiting step in hydrocarbon production from shales. Our results indicate that the composition of the produced fluids changes with time, transitioning from a dry/wet gas to a gas condensate, becoming heavier with time. However, at any given time, the produced fluid is significantly lighter than the in-situ fluid. The species with the greatest mobility is methane, which is expected because it is the lightest molecule in the fluid and its ability to migrate is greater than that of all other fluid molecules. A sensitivity analysis shows that the produced fluid composition strongly depends on the initial composition of the fluids in organic pores.

Low temperature air injection with solvents in heavy-oil containing naturally fractured reservoirs: Effects of matrix/fracture properties and temperature on recovery

Implementation of in situ combustion process in fractured reservoirs might be risky due to quick breakthrough of unconsumed oxygen to the producers. Recently, we proposed low temperature air–solvent injection (LTASI) as an alternative process to overcome this problem (SPE 149896 and 174542). This process involved oxygen addition reactions (low temperature oxidation) rather than bond scission reactions (in situ combustion). Because increase in matrix oil viscosity is the drawback associated with oxygen addition reactions, reduction of it by adding hydrocarbon solvent into the air injected can be a solution. Determination of optimal application conditions of this kind of expensive and risky process is critically important.Based on promising results reported in SPE 174542, we conducted new static experiments of air and hydrocarbon solvent injection at low temperature oxidation conditions that complement previous lab studies. Vertically situated sandstone and limestone samples were exposed to air+propane (or butane) mixture under static conditions mimicking huff-and-puff (cyclic injection) type injection. The main purpose was to determine the effect of change in matrix size as well as different matrix/fracture volume ratios on matrix oil recovery. This is important because this method is proposed as a cyclic injection application and the cyclic times are determined by the volume of the fractures, which are to be filled with injected air/propane and the diffusion rate of these gases into matrix.During the experiments, the gas was injected in the annular space representing a fracture surrounding a heavy oil saturated core at certain pressure and temperature for a certain (soaking) time period. The produced gas and liquid oil were tested in different cycles using a gas chromatograph. The effect of fracture volume, matrix size, and application temperature on the produced fluid composition was studied.An extensive experimental schedule for static diffusion experiments was accomplished in which the effect of some variables in the oil recovery and oxygen consumption was analyzed. The variables evaluated include rock type (sandstone, limestone), temperature (75, 150, 200°C), fracture volume, solvent type (C3, C4), matrix size (2-in. diameter, 6-in. length; 3.2-in. diameter, 9-in. length), and injection sequences (Air/C3/Air, C3/Air/C3, etc.). A total of 21 experiments were carried out for a comparative analysis and optimal application conditions yielding increased oil recovery and increased oxygen consumption through oxidation reactions in the matrix were determined. These optimal conditions will provide reduced risk due to early breakthrough of unconsumed oxygen and maximized profit, which is needed due to the high cost of propane.

Experimental Study of Dehydration Effect of Crude Oil in Multi-purpose Station

Crude oil dehydration process in multi-purpose station is of great importance, in which there are a lot of confounding factors and parameters. In order to solve the dewatering difficulty in multi-purpose station of Liaohe Oilfield during operation, we designed a laboratory experiment of thermo-chemical setting dehydration, and analyze these factors impacting the liquid mixture separation of oil and water from the districts, including to liquid water content, dehydration temperature, PH value of crude oil solution, demulsifier dosing concentration, produced fluid composition. This research shows that: adjusting the technological parameters in a reasonable range, is both beneficial to dewatering and improving heavy oil dehydration effect, and of great significance of improving the downstream production standard. Key words : Heavy oil; Multi-purpose station; Crude oil emulsion; Demulsification

Environmental Risk Arising From Well-Construction Failure—Differences Between Barrier and Well Failure, and Estimates of Failure Frequency Across Common Well Types, Locations, and Well Age

Summary Do oil and gas wells leak to the environment? This paper will show the great majority of wells do not pollute. The purpose of this paper is to explain basic concepts of well construction and illustrate differences between single-barrier failure in multiple-barrier well design and outright well-integrity failure that could lead to pollution by use of published investigations and reviews from data sets of more than 600,000 wells worldwide. For US wells, while individual-barrier failures (containment maintained and no pollution indicated) in a specific well group may range from very low to several percent (depending on geographical area, operator, era, well type, and maintenance quality), actual well-integrity failures are very rare. Well-integrity failure occurs when all barriers fail and a leak is possible. True well-integrity-failure rates are two to three orders of magnitude lower than single-barrier-failure rates. When one of these rare total-well-integrity failures occurs, gas is the most common fluid lost. Common final-barrier leak points are failed gaskets or valves at the surface and are easily and quickly repaired. If the failure is in the subsurface, an outward leak is uncommon because of a lower pressure gradient in the well than in outside formations. Subsurface leaks in oil and gas wells are rare, and routinely comprise exterior-formation salt water leaking into the well toward the lower pressure in the well. Failure frequencies are estimated for wells in several specific sets of environmental conditions (i.e., location, geologic strata, produced-fluid composition, and soils). Estimate accuracy depends on a sufficient database of wells with documented failures, divided into (1) barrier failures in a multiple-barrier system that did not create pollution, and (2) well-integrity failures that created a leak path, whether or not pollution was created. Estimated failure-frequency comparisons are valid only for a specific set of wells operating under the same conditions with similar design and construction quality. Well age and construction era are important variables. There is absolutely no universal definition for well-failure frequency.

The Impact of Oil Viscosity Heterogeneity on the Production Characteristics of Tar Sand and Heavy Oil Reservoirs. Part II: Intelligent, Geotailored Recovery Processes in Compositionally Graded Reservoirs

Abstract Compositional and fluid property gradients are common and documented in conventional heavy oilfields and in super heavy oil occurrences such as oil sand reservoirs. In the severely biodegraded oils of both Athabasca and Peace River oil sand reservoirs, highly non-linear vertical and lateral chemical compositional and fluid viscosity gradients are common and have been shown to dramatically impact existing generation recovery processes such as SAGD and CSS. The fluid and geological heterogeneities at a variety of spatial scales in heavy oil and bitumen reservoirs, combined with the dynamic evolution of produced fluids during solvent or thermal recovery, should be integrated into recovery methods tailored to each reservoir which are operated using time-variant production strategies informed by produced fluid composition, flow rates and detailed history matching. We describe here, two new approaches of a new generation of transitional and initial thermal recovery processes that take advantage of mobility gradients: JAGD (J-well and Gravity Drainage) and gSAGD (mobility ratio optimized SAGD), which demonstrate significant improvements in recovery, economics and, thus, carbon dioxide emissions over existing thermal methods. Well configurations tailored to specific reservoir geometries and properties as well as fluid property distributions for primary thermal recovery increase initial production by 50 to 100%. Substantial cost savings are achieved in transitional cold primary to thermal secondary recovery methods (JAGD) by using a production J-well placed below what is initially a CHOPS production well, which is then later used to inject steam, as in SAGD. Three-dimensional reservoir simulations predict 25% more oil recovery with up to a 50% decrease in cumulative steam-oil ratio compared to standard SAGD in an identical reservoir. The JAGD process has many similarities to SAGD, such as steam trap control and potential for low pressure and solvent-assisted operation. Such geotailored processes (processes tailored, operated and optimized to reservoir fluid and geological heterogeneities) are expected to outperform conventional 'off the shelf' well placement designs and operating strategies. Introduction The bulk of the world's petroleum resources are stored in heavy oil and oil sand reservoirs. While some of this resource can be recovered by geotolerant (tolerant of unfavourable geology) recovery processes such as mining, these procedures are only suitable for shallow resources, are very costly and have high carbon dioxide emissions and other environmental penalties. Most of the world's heavy oil and bitumen resources are too deep to mine and so in situ recovery methods predominate. In situ recovery of viscous and poor quality oils currently relies on either high pressure primary production, as in cold heavy oil production, or thermal and/or solvent-based methods to mobilize the oil by reducing its viscosity. Average recoveries from heavy oil and oil sand reservoirs are typically low ranging from 5 to 15% for cold heavy oil production and from 30 to 85% for steam-based in situ processes. However, such processes are not very geotolerant. Also, profit margins are small because of high capital and operational costs.

Shortened Modeling Time Seen With Suite Concept in Reservoir Sampling

Wireline-testing-tool capabilities and efficiencies are dramatically changing the value of formation-sampling and -testing programs. As real-time pressure-volume-temperature (PVT) simulation and collected formation samples are obtained closer to in-situ conditions, the accurate determination of produced-fluid composition is affecting project cycle times and reducing developmental risks, offering a narrow window of opportunity for operators to improve cost-efficiency. While the value of formation characterization and samples remains in identifying the production potential of targeted reservoirs and design and development of production facilities, sampling is also an effective means of identifying water aquifers that require isolation during completion and confirming gas/oil/water contacts. In the past, it has been necessary for engineers to first understand the reservoir’s characterization and sampling needs, then define the proper tools or services, and finally to locate compatible tools. Replacing traditional drillstem tests with a combination service portfolio that includes a wireline single-phase sampling program, real-time PVT predictions, and real-time contamination monitoring can potentially improve the accuracy of reservoir data and the quality of fluid samples and have a beneficial impact on essential design needs. Accurate determination of produced-fluid phase behavior and composition are valuable data used in designing completions, production facilities, and flow-assurance programs. A combination service package, RESolution, was recently launched by Baker Atlas and consists of reservoir-fluid characterization, testing, and sampling services that provide real-time reservoir pressures, in-situ fluid samples, and fluid characterization. The portfolio service uses one logging instrument, the RCI Reservoir Characterization Instrument, with single-phase tanks that gather fluid samples downhole and then overpressure them to preserve the samples at in-situ conditions. By creating a state of overpressure before bringing the sample to the surface, the typical loss of pressure and cooling effect during the journey out of the wellbore results in retrieval of the sample at reservoir conditions.

Engineering Calculations of Gas-Condensate-Well Productivity

Summary Accurate forecasting of gas-condensate-well productivity usually requires fine-grid numerical simulation to model the formation of the condensate bank and to account for high-velocity phenomena such as non-Darcy flow and changes in relative permeability at high capillary number. This paper presents a new technique for forecasting the performance of gas-condensate wells, using simpler techniques that can be used in a spreadsheet. The calculation uses a material-balance model for reservoir depletion and a two-phase pseudopressure integral for well inflow performance. The pseudopressure-integral technique has been extended to include high-velocity effects and to allow for the change in produced-fluid composition caused by the formation of the condensate bank. The new technique has been tested by comparison with the results of fine-grid compositional simulation, and the results are in good agreement for a wide range of cases covering vertical, horizontal, and hydraulically fractured wells. The spreadsheet-model approach provides a useful tool for rapid forecasts of condensate-well performance, for examining the effects of condensate blockage in different well types, or for studying sensitivities. It is also valuable where simple models of condensate-reservoir performance are required for use in integrated studies involving issues such as surface facilities, drilling schedules, and gas sales contracts.

Quantitative Evaluation of Produced Hydrocarbon Compositions And Injectant Reproduction In Gas-miscible Floods

Abstract It is not trivial to identify and to quantitatively monitor production of injectants such as solvent and chase gas during a commercial gas-miscible flood. A new methodology was developed for evaluating produced amounts of those injectants and reservoir oil using readily available field data. This methodology follows two major logical steps. The first step is to determine overall compositions of the produced hydrocarbons. The new method can uniquely determine the total produced hydrocarbon composition from available field data, namely a separator gas composition and a produced gas-oil ratio, using an equation of state adequately tuned for specific crude oil. The second step is to determine the most plausible proportions of injected solvent, chase gas and reservoir oil in the produced hydrocarbon composition with the knowledge of the respective compositions. The entire process was packaged in computer software which had been tested for its reliability. The software has been in use for the past two years in Imperial Oil's gas-miscible projects for reporting solvent and chase-gas production. In these field applications, the software has proved to be capable of calculating solvent and chase-gas contributions even in situations with gas-lift wells. Introduction The first attempt of utilizing flash calculations based on the equation of state for determining injectant content in produced hydrocarbon during a hydrocarbon gas miscible flood was reported by Wu et al.(1) in 1989. Their method was as follows; first create a hypothetical mixture of known reservoir oil and solvent compositions, then flash the mixture using a tuned equation of state at a first separator condition. This trial-and-error process was repeated with a change of the mixing ratio until the calculated separator-gas composition agreed with the measured composition. Their method would be able to determine correctly the produced fluid compositions only if the produced fluid from the reservoir were a straight mixture of the assigned oil and solvent compositions. Unfortunately, injected solvent compositions vary with time and the displacement in the reservoir is not as ideal as straight mixing. As a result, they reported marked disagreements in GOR values between measured and predicted values. The new methodology discussed here does not require a priori knowledge of injectant compositions for the determination of a produced fluid composition. Instead, a produced fluid composition is determined solely from measured separator gas composition and GOR value. An equation of state tuned to specific reservoir oil can determine a separator liquid composition which is in equilibrium with the measured gas composition. The produced fluid composition should be on the tie line connecting these gas and liquid compositions, and the GOR value determines the location of the produced fluid composition on the tie line. Once the produced fluid composition is determined, contributions of reservoir oil and injectants to form this composition are determined in a mathematically rigorous manner. The important feature of this methodology is that it can determine mole fractions of multiple injectants in the produced fluid. The new methodology was packaged in software called PFAN (Produced Fluid Analysis).