Polymer and alkali-polymer (AP) flooding are investigated in laboratory corefloods for potential application in a 2000 cP - 5000 cP heavy oil field. An augmentation of oil recovery is noted with the addition of very low concentrations of partiallyhydrolyzed polyacrylamide (HPAM), either in secondary or tertiary (i.e. after waterflooding) injection. However, increasing polymer viscosity from 3 cP to 60 cP does not significantly change recovery from two pore volumes (PV) of tertiary polymer injection. Injection of alkali with polymer either in tertiary mode or subsequent to polymer injection yields a significant increase in oil recovery, and is accompanied by a drop in pressure gradient when it follows a polymer slug of similar viscosity.
Existing scaling groups for viscous instability are investigated and corefloods in this study and others are found to be in the transition zone or the pseudostable region, while field floods are all in the latter. Growing evidence suggests that polymer flooding can be economically applied to very viscous oils, despite the pessimistic predictions of currently available scaling groups.
The paper is devoted to the problem and results of applying up-to-date nuclear spectrometry logs including C/O log for high-viscosity oil pool studies. Information about applied measurement technologies, tools, new comprehensive interpretation techniques has been given. Practical examples of the effectiveness of the nuclear logs in formation water salinity evaluation and localization of water flooded zones in oil recovery by thermal methods have been shown. Techniques for reliable forecasting of the characteristics of the inflows obtained in reservoir tests have been developed.
The problem of high-viscosity oil pool development is urgent both in Russia and many other countries. The major difficulties of such pool development are caused by physicochemical properties of the hydrocarbon raw materials - their high viscosity and density. Such problems can be solved using various techniques for enhanced oil recovery. Thermal techniques are the most widely used ones among them. In some cases hydrocarbon solvents, surfactants, polymer solutions or other chemicals are injected.
This paper continues the series of works commenced in 2008 and devoted to creation of nuclear logging techniques on a Russian oil field with potentially high reserves of high-viscosity oils. The oil field has been developed since 1977.
To enhance oil recovery from the formations and maintain the reservoir pressure in the field, hot water was injected, and steam was patternly injected into the production horizons.
The following pool features can be highlighted:
- Two reservoir types can be found: 1) a fractured, high-porosity, cavern and karst one having total porosity 10 to 30 % and abnormally high permeability reaching tens of square micrometers; 2) a porous (matrix) one having a low permeability, 0.001 to 0.01 square micrometers. The reservoirs have a heterogeneous structure, the sections feature highly divided and discontinued permeable zones.
- The matrix of the reservoirs is formed of carbonates containing limestones of various structural and genetical types, partially dolomitized, in some places of a secondary origin, with silicate and ferruginous mineral inclusions.
- The hydrocarbon raw material contains much tar, has hydrogen sulfide, features high density (0.95 to 0.98 g/cm3) and viscosity (344 to 2024 mPa×sec) at the average formation temperature of 40 º?.
- Organic matter is present in the rock. It is represented by various bitumoids (such as oils, tars, asphaltenes. Bitumenization occurs throughout the whole production section without any special regularity and not always accompanied with any elevated natural gamma-ray activity.
The development technologies applied in the field can change to some extent the natural characteristics of the pool, which complicates seriously the task of studying its current state - in particular, it can complicate reservoir depletion degree evaluation.
The long-term heat attacks can, firstly, change the temperature and pressure conditions in the pool, and, secondly, the formation fluid can be significantly displaced by sweet water in permeable reservoirs. Both the first and second outer affecting factors disturb the hydrogeological and geochemical equilibrium in the pool. All that leads to greater errors in evaluation of capacity properties and saturation in the reservoirs. Since the pore volume determines substantially the error in the fluid contents evaluated, it is clear that no acceptably reliable saturation parameters can be achieved when the porosity is evaluated incorrectly. All that demands stricter attention to geophysical control methods.
The description of heptanes and heavier components (C7+) in reservoir fluids can be important for equation of state (EOS) predictions of phase and volumetric behavior. This paper describes a procedure for C7+ characterization of heavy oil based on crude assay data which are typically measured for refining and marketing applications.
C7+ characterization is defined as (1) modeling the molar distribution that quantifies molar (mass) amounts and molecular weights of discrete plus fractions, (2) estimating specific gravity and normal boiling point of plus fractions, and (3) estimating EOS and viscosity-model parameters Tc, pc, ?, Vc, s (volume shift) and binary interaction parameters (BIPs) kij of plus fractions.
From crude assay data, we use the mass fractions and overall sample molecular weight to determine the parameters for gamma molar distribution parameters - shape (a), lower bound (?) and average plus molecular weight (Mo) in the gamma distribution model. The molar distribution model, together with measured assay-cut specific gravity and boiling point data, are used to determine parameters in the Soreide correlation describing specific gravity-molecular weight relationship. The inter-correlation of assay data is also affected by correlation used between molecular weight, boiling point, and specific gravity. We use a parameter, fTwu, where fTwu=1 honors the Twu correlation exactly, while fTwu= 0 honors a pure-paraffinic correlation between molecular weight and boiling point (independent of specific gravity).
Viscosities of each fraction are correlated against measured data and/or standard-pressure liquid viscosity estimates from the Orrick-Erbar correlation. We use the Lorentz-Bray-Clark (LBC) correlation, where fraction critical volumes are adjusted to give consistency between the LBC estimates for each fraction individually. This approach to determining the critical volumes has proven useful in making the LBC more predictive for overall oil mixture viscosities at reservoir conditions.
Solvent vapour extraction (VAPEX) process is an economically viable, technically sound, and environmentally friendly insitu heavy oil recovery method to exploit tremendous heavy oil and bitumen reserves. In this recovery process, significant heavy oil viscosity reduction is achieved through sufficient solvent dissolution and possible asphaltene precipitation. Over the past two decades, several researchers have carefully studied the effects of some major factors on the VAPEX process, such as the test pressure, reservoir porosity and permeability, solvent and heavy oil types, well configuration, and connate water saturation. However, it is unclear how waterflooding and solvent injection will affect a typical VAPEX process.
In this paper, waterflooding and solvent injection effects are experimentally studied by using a visual rectangular sandpacked high-pressure VAPEX physical model with a low permeability. The physical model is packed and then saturated with a heavy oil sample at the connate water saturation. Pure propane and a mixture of n-butane and methane are used as respective solvents to extract two different heavy oil samples. The waterflooding effect is examined by performing a series of VAPEX tests with the initial waterflooding, prior to the subsequent solvent injection/soaking. In addition to the visual observation of the solvent chamber evolution, the heavy oil production rate, produced solvent-oil ratio, and asphaltene content of the produced heavy oil are measured during the waterflooding and solvent injection/soaking. It is found that the initial waterflooding causes an oil production reduction in the subsequent solvent injection. Also solvent breakthrough occurs earlier and a small amount of water is produced afterwards. This is because the initial waterflooding creates some lowresistance channels for the injected solvent to bypass the untouched heavy oil. As a result, the heavy oil is not diluted enough to be produced during the subsequent solvent injection/soaking. In the absence of waterflooding, however, solvent injection alone can increase the heavy oil production in comparison with the solvent-soaking process. Moreover, it is visually observed that solvent injection leads to less asphaltene deposition onto the porous media. This is quantitatively verified by a higher measured asphaltene content of the produced heavy oil at a higher solvent injection rate.
Meddaugh, William Scott (Chevron) | Osterloh, W. Terry (Chevron Corp) | Toomey, Niall (Chevron) | Bachtel, Steve (Chevron) | Champenoy, Nicole (Chevron) | Rowan, Dana E. (Chevron Global Upstream & Gas) | Gonzalez, Gregorio (Chevron Corp) | Aziz, Shamsul (Chevron Corp) | Hoadley, Steve Floyd (Joint Operations) | Brown, Joel (Saudi Arabian Texaco Inc.) | Al-Dhafeeri, Fahad M. (Saudi Arabian Chevron) | Deemer, Arthur Ruch
The Paleocene/Eocene age First Eocene dolomite reservoir is estimated to contain than 10 billion barrels of oil of which only a small percentage will be produced during primary development. Consequently, steam flooding is being investigated as an appropriate EOR option. A 1.25-acre, single pattern pilot (SST) and a 40-acre, 16 pattern pilot (LSP) are in progress. The detailed pilot area log, core, and seismic data provide a unique opportunity to assess reservoir heterogeneity. Analysis of temperature and petrophysical logs obtained in a temperature observation well located 35 feet from the SST injector show that a vertical barrier to steam migration exists. Two, relatively thick, very low porosity and very low permeability nodular evaporite-rich zones that were predicted to be the most likely barriers do not appear to be a vertical barrier. Instead, an interval characterized by numerous thin, cycle caps, characterized by muddy, finely crystalline dolomites interpreted to be tidal flat facies may be the vertical barrier. Each of these cycle caps also exhibit signs of subaerial exposure which may also contribute to the generally low porosity and very low permeability of the cycle caps. Detailed studies, including micro-permeameter measurements, quantitative mineralogical studies, and micro-CT scans were used to further characterize this interval. The geological assessments of heterogeneity are supplemented by a history-matched simulation model that suggests the evaporite-rich zones may have acted as short term baffles but that the vertical barrier to steam migration is coincident with the interval with abundant tidal flat cycle caps and exposure surfaces. Geological and other reservoir data obtained from the LSP suggest that similar vertical barriers may exist in the pilot area. Early steamflooding results show a very positive response to steam injection as well as multiple thermal "events?? (most likely baffles rather than barriers) in the lowermost flooded zones at the LSP. The LSP data allows inferences to be made regarding the occurrence and distribution of lateral high permeability "connections?? between injectors and producers as well as the overall reservoir response to steam injection. While the rapid temperature response observed in a few wells may reflect localized fractures or karst-like zones, numerical simulation using very fine grids (1.25 m cell size) shows that some of the LSP wells may experience very short breakthrough times without the need for fracture or karst-like zones.
In this paper, techniques have been developed to examine the enhanced swelling effect and viscosity reduction of CO2-saturated heavy oil with addition of rich solvent C3H8. Experimentally, PVT tests are conducted to measure the saturation pressure, swelling factor and viscosity of the C3H8-heavy oil system and C3H8-CO2-heavy oil system, respectively. It has been found that an increased swelling effect of heavy oil is obtained by adding rich solvent C3H8 into CO2 stream. An enhanced viscosity reduction of the CO2-heavy oil system is also achieved in the presence of rich solvents such as C3H8. Theoretically, two binary interaction parameter (BIP) correlations in Peng-Robinson equation of state (PR-EOS) have been proposed for respectively characterizing CO2-heavy oil systems and C3H8-heavy oil systems by treating each oil sample as a single pseudocomponent with its molecular weight and specific gravity. The BIP correlations together with the PR-EOS can be used to predict the saturation pressures and swelling factors of the C3H8-CO2-heavy oil systems with a good accuracy. Also, in comparison to other mixing rules, the Lobe's mixing rule is found to be more appropriate for quantifying viscosity reduction of the heavy oil with dissolution of CO2 and/or C3H8.
Cold Heavy Oil Production with Sand (CHOPS) is a non-thermal heavy oil recovery technique used primarily in the heavy oil belt in eastern Alberta and western Saskatchewan. Under CHOPS, typical recovery factors are between 5 and 15% with the average being under 10%. This leaves approximately 90% of the oil in the ground after the process becomes uneconomic, making CHOPS wells and fields, prime candidates for EOR and field optimization. CHOPS wells show an enhancement in production rates compared to conventional primary production, which is explained by the formation of high permeability channels known as wormholes. The formation of wormholes has been shown to exist in laboratory experiments as well as field experiments conducted with fluorescein dyes.
The major mechanisms for CHOPS production are foamy oil flow, sand failure and sand production. Foamy oil flow aids in mobilizing sand and reservoir fluids leading to the formation of wormholes. Foamy oil behaviour cannot be effectively modeled by conventional PVT behaviour, leading to the use of a kinetic model, which can be easily implemented with the kinetic reaction features in CMG STARS. The sand is mobilized due to sand failure, determined by a minimum fluidization velocity. The individual wormholes will be modeled in CMG STARS using existing wellbore features. The ability to grow a wellbore dynamically is not built into STARS, leading to the creation of a Dynamic Wellbore Module. The module continuously restarts the STARS simulation runs and determines the growth criteria for wormhole growth. If the criterion is met, the wormhole is grown in the appropriate direction; otherwise the simulation is run again until the criterion is met.
The proposed model incorporates the major factors in CHOPS production and shows an adequate to fit to model general production trends of typical CHOPS well. The model demonstrates there is a criterion for which wormhole growth occurs as wells as limits its extent of growth in a reservoir. The model can then be used for follow-up EOR processes such as cycle solvent injection as well as field optimization.
The metal-to-metal progressing cavity pump is an attractive artificial lift for heavy oils in cold or hot application. The principal objective of this paper is to present the latest developments in numerical simulations tools aimed at understanding and optimizing the operation of a PCP with metallic stator. This paper is divided into three parts: the first focusing on the precise implementation of a viscoplastic thixotropic model while the second is the validation of the numerical models developed around 3D calculations based on a volumetric pump and comparing them to experimental data. The last part is oriented towards the full 3D fluid structure interaction model, used to estimate the stress and strain amplitudes in the metallic stator, to finaly predict its life span or optimize its design.
The Duri field, operated by Chevron under a production sharing contract with Government of Indonesia, is located in Riau province of central Sumatra about 120 km northwest of the city of Pekanbaru. The Duri Steamflood (DSF) Project is the largest Steamflood project in the world. Duri field was discovered in 1941 and start producing with primary production in 1958. Steamflood project started in 1985 and reached the peak production of 300,000 barrels oil per day later on late year 1994. Many well technologies have been applied, related to producer well completion and sand control, injector well completion, artificial lifts, and horizontal drilling to optimize the oil recovery. Heat management process was established to manage the steam injection efficiently. The DSF project was developed from Area-1 until Area-12 with different pattern sizes and configurations. The pattern sizes range from 5.5 acres to 15.5 acres. Pattern configurations vary and consist of 5-spot inverted 7-spot inverted and 9-spot inverted patterns. The DSF plans for further expansion to northern part of Duri field by developing new areas and other areas such as Duri "Ring??, the area surrounding the existing producing field. Until 1998, steam was generated using oil as fuel but in year 2000, generators were converted to natural gas. The gas consumption reaches 414 MMscfd and mostly supplied from neighbored production sharing contractor ConocoPhillips using 28 inch x 530km pipeline transmission operated by 3rd party.
On 29 September 2010, when DSF was producing 190,000 barrels oil per day, a failure event occurred that resulted in a release of gas from the pipeline. The accident cut the gas supply to DSF, caused the shutdown of steam generation facilities, and forced the world's largest steamflood project to shut some of the producer wells for several days. This incident was the first "no-steam?? incident to Duri steamflood project operation.
The impact was severe. Production dropped to 58,000 barrel oil per day, and gradually increased back after the gas supply was ramped-up to normal levels. The gas supply was ramped-up and back to normal in 25 days. The production ramped-up, reached the peak slightly lower than before the event and production is continuing to recover with different mode where the decline is lower than before the incident. After the initial incident, there were other events, related to gas supply issues and interruptions of steam supply from cogeneration plant (COGEN) that have negatively impacted the production recovery. This paper shows the on-going massive efforts of Chevron and Government of Indonesia to bring the world's largest steamflood project to full recovery and sustainably rejuvenate the Duri Field production.
This paper presents the planning and development of a project in Samaria Neogeno field, which is a heavy oil field that is located 17 kilometers from Villahermosa, Mexico. The front-end loading (FEL) method was used to design the development plan of the Samaria Neogeno field and to complete the project. FEL is considered to be an international best practice. The Samaria Neogeno field is currently undergoing a period of substantial development, which has resulted in a potential production increase of 30,000 bbl/day. This project is a result of the collaborative efforts of PEMEX and Halliburton.
In general terms, the FEL method includes three stages: visualization, conceptualization, and design. The primary activities include the identification and characterization of the uncertainty variables, definition of decision variables and scenarios, and a stochastic simulation of each scenario. One scenario represents a specific exploitation plan. By using the stochastic simulation process, the degree of risk is quantified and measured by standard deviation; consequently, each scenario evaluated was associated with its level of risk. The consideration of the standard deviation parameter, in addition to the economic indicators, promotes better decision making.
The development of the Samaria Neogeno project has been through the three FEL stages, and the execution of the steam injection pilot project. In the visualization stage, multiple scenarios were evaluated; the higher value options were designed for cold production in the early years, followed by the incorporation of hot production in the short- and mid-term phases. In the conceptualization stage, the most valuable scenario was selected, which led to the development of a steam injection pilot project. The steam injection pilot project represented the largest contribution of information regarding the reservoir and response with steam injection. The average production per well increased from 240 to 1,170 bbl/day, and 30 to 40 barrels of oil was recovered for each ton of steam injected. After obtaining these results, a mass development plan was created, and this plan will be implemented during the current year.
The successful results at Samaria Neogeno field highlights the added value of the FEL method as an international best practice.