We present a systematic study of laboratory tests of alternative chemical formulations for a chemical flood design and application. Aqueous and microemulsion phase behavior tests have previously been shown to be a rapid, inexpensive and highly effective means to select the best chemicals and minimize the need for relatively expensive core flood tests. Microemulsion phase behavior testing was therefore conducted using various combinations of surfactants, co-solvents and alkalis with a particular crude oil and reservoir conditions of interest. Branched alcohol propoxy sulfates and internal olefin sulfonates showed high performance in these tests, even when mixed with both conventional and novel alkali agents. Systematic screening methods helped tailor and fine-tune chemical mixtures to perform well under the given design constraints. The best chemical formulations were validated in core flood experiments, and compared in terms of both oil recovery and surfactant retention in cores. Each of the four best formulations tested in core floods gave nearly 100% oil recovery and very low surfactant adsorption. The two formulations with conventional and novel alkali agents gave almost zero surfactant retention. In standard practice, soft water must be used with alkali, but we show how ASP flooding can be used in this case even with very hard, saline brine.
Today the oil market is experiencing high production demand from mature oil fields in a possibly near-future carbon-constrained world. This demand will result in numerous new anthropogenic CO2 sources near oil fields currently producing under primary production. Many of the new areas for CO2 EOR application will lie where sandstone reservoirs dominate, with their higher-quality petrophysical characteristics. A review of today's and previous experiences in the Gulf Coast could help when new floods are designed and implemented in pioneer areas.
To characterize Gulf Coast sandstone CO2 EOR experience, information from both full floods and pilots was assembled. Published and publicly available data were used in the study, emphasizing geologic setting of the reservoir, flooding methods, slug size, CO2 utilization, and other measures that indicate flood results.
CO2 EOR is applied in reservoirs deposited as barrier/strandplain, submarine-fan, and fluvial/deltaic sandstones. Solvent gases are predominantly combinations of CO2, N2, and CH4, and are applied as WAG, gravity-stable, continuous injection, and huff n' puff flooding methods. Tools such as pulsed neutron and pressure and sponge cores measure pre-EOR residual oil saturations to be between 0.2 and 0.38, averaging 0.25. Expected recovery efficiency for all flood types range from 17 to 23% of OOIP, with permeable Gulf Coast floods typically displaying 5 to 6 months' breakthrough timing. Applying recovery characteristics from the projects summarized and applying CO2 screening criteria resulted in delineation of an oil-resource target of 4.7 BSTB of miscible floodable oil along the Gulf Coast.
Deposition of solid hydrocarbons such as asphaltene and wax near the wellbore and in the tubing is known to cause decline in the well production performance. Various mitigation methods such as chemical wax inhibition, thermal insulation, and coiled tubing clearance are repetitive and exhaustive. These methods could temporarily remove deposits but not prevent them from reoccurrence. On the other hand, the thermo-chemical method utilizing acid-base reactions seems to be offering the most effective and simple solution to the problem. Reaction products and heat from the acid-base reactions could be utilized to dissolve and disperse wax or asphaltene deposition in addition to changing the wettability profile. The present study is to evaluate the performance of acidized amines for mitigating formation damage and improve oil recovery in the Penara Field, offshore Peninsular Malaysia. Wells in the field have been recording massive production decline of more than 5000 stb/d despite continuous treatment of pour point depressant, wax dispersant, de-emulsifier and frequent tubing clearance activities.
Physical observation and interfacial tension measurement were carried out to qualitatively and quantitatively measure the performance of the acidized amines. Improvement in the oil recovery was measured through coreflooding test. The study found that acidized amines by-products dispersed the suspended wax solid and prevented it from re-depositing after 48 hours. Thus, oil recovery increased to 51.3 % for non waxy-liquid crude and 13.0 % for waxy-gelled crude. These findings from the laboratory were further validated by production optimization using Wellflo.
The thermochemical method utilizing acidized amines is simple and yet experimentally proved to be effective in solving the wax related problem. Considering the reserve potential in the Penara Field and supported by sufficient well data, the incremental production of 22 % could be predicted.
This paper investigates ways in which CO2 storage in low-permeability formations might be made viable and how such formations might compete with more distant formations with higher permeability. Hypothetical, but realistic cases are postulated to examine the effect of reservoir engineering and economic sensitivities. The cases compare (a) a large CO2 source with nearby abundant low-permeability pore space (0.1-10md) with (b) the same source with storage in a remote high permeability (100md) site. Based on reservoir engineering and economic analyses, the paper quantifies the injectivity of the sites, assesses the number of wells required and finally estimates the costs of capturing CO2, transporting it to the storage sites and injecting it into the sub-surface.
The paper shows that, for the given assumptions, Carbon Capture and Storage (CCS) in the remote high-permeability formation can be significantly cheaper than CCS in the low-permeability storage site. The cost advantage of the considerably higher permeabilities expected in the remote area by far outweighs the cost of transport over the extra distance. This is the case despite applying horizontal drilling and fracturing technologies.
The economics of both the low and high permeability formations can be improved markedly by using horizontal rather than vertical wells. However, CCS in the remote high-permeability storage site still retains its cost advantage using this technology. Fracturing increases injectivity considerably for low permeability reservoirs and for both vertical and horizontal wells. However, it does not have a significant effect on reservoirs that have high permeability. Therefore, the technology helps injection in the low-permeability storage site much more than in the remote high-permeability storage formations. However, although under some conditions the relative economics of the low-permeability formation can be improved significantly by fracturing the low-permeability formation, the improvement is not sufficient to reverse the cost disadvantage of the low-permeability storage site.
To evaluate the amount of bypassed oil in a CO2 flood, it is necessary to obtain some estimate of the remaining oil saturation. Near wellbore oil saturation determination requires a tool or sequence of tools that is able to distinguish oil from other phases that may be present in situ especially when those phases are miscible with the oil.
This paper presents the combined use of several neutron tools to evaluate the remaining oil saturation in a miscible CO2 flood. These techniques are not time lapse techniques and so are applicable even where there are no base cased-hole logs to evaluate.
These methods are applicable in areas where CO2 has been injected for a long period of time without a base pre-CO2 log. The techniques work best with a full suite of open-hole logs to characterize the petrophysical properties of the well and where heterogeneity effects control the displacement process. If petrophysical properties are known or reasonably estimated from other data available, the proposed methods can provide an estimate to the oil saturation that should be adequate to allow go/no go decisions.
De Zwart, Albert Hendrik (Shell Intl E&P) | van Batenburg, Diederik W. (Shell E&P Co.) | Blom, Carl P.A. (Shell Intl E&P) | Tsolakidis, Argyrios (Shell Intl E&P) | Glandt, Carlos Alberto (Shell Intl. E&P BV) | Boerrigter, Paul (Shell International E&P)
High Pressure Air Injection (HPAI) is a potentially attractive enhanced oil recovery method for deep, high-pressure light oil reservoirs after waterflooding. The advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas, is its availability at any location. HPAI has been successfully applied in the Williston Basin for more than twenty years and is currently being considered by many operators for application in their assets.
Evaluation of the applicability of HPAI requires conducting laboratory experiments under reservoir temperature and pressure conditions to confirm crude auto-ignition and to assess the burn characteristics of the crude/reservoir rock system. The ensuing estimation of the potential incremental recovery from the application of HPAI in the reservoir under consideration requires fit-for-purpose numerical modeling. Typically, the flue gas generated in-situ by combustion leads to in an immiscible gas drive, where the stripping of volatile components is a key recovery mechanism. HPAI has therefore, in some instances, been modeled as an isothermal flue gas drive, employing an Equation of State (EOS) methodology. This approach, however, neglects combustion and its effects on both displacement and sweep. Furthermore, the EOS approach cannot predict if, and when, oxygen breakthrough at producers occurs. Combustion can be included in a limited fashion in simulations at the expense of extra computational time and complexity. In the available literature, combustion is taken generally into account under quite simplified conditions.
This paper addresses the role that combustion plays on the incremental recovery of HPAI. Numerical simulations were conducted in a 3D model with real geological features. In order to capture more realistically the physics of the combustion front, a reservoir simulator with dynamic gridding capabilities was used. Kinetic parameters were based on the combustion tube laboratory experiments. The impact of combustion on residual oil, sweep efficiency and predicted project lifetime is presented by comparing isothermal EOS-simulations and multi-component combustion runs.
Heterogeneity measures have a long history in the oil and gas industry but have fallen somewhat out of favor in recent years with the advent of more statistically robust characterization tools. Theoretically-based correlations between heterogeneity measures and recoveries at various stages of a waterflood appear to be one of the primary tools in the design and early evaluation of floods when they were initially proposed. Field-wide reports of the heterogeneity measures and their relationship to enhanced recovery response were also reported in the literature, but it is unclear as to whether general correlations were developed or widely used as they were for waterflooding.
In this work we evaluate several heterogeneity measures in terms of recovery efficiency and utilization rate in a mature CO2 flood. Core studies available from 41% of the wells in the Little Creek Field, Mississippi were used to compute various heterogeneity measures and the resulting values were correlated with pattern-by-pattern and development area recoveries and CO2 utilization rates at various times over the life of the flood. Weak correlation trends were found for most of the measures when recoveries were evaluated. Slightly stronger correlations were found with utilization rates.
Much more significantly, mapping of the well-by-well heterogeneity measures appear to show geological trends better than traditional maps of the basic parameters that make up the measures. These geological trends were then successfully used to adjust rock-types and guide geostatistical modeling of permeability and porosity when performing reservoir modeling and history matching.
Alkaline/surfactant/polymer (ASP) flooding is of increasing interest and importance due to high oil prices and the need to increase oil production. The benefits of combining alkali with surfactant are well established. The alkali has very important benefits such as lowering interfacial tension and reducing adsorption of anionic surfactants that decrease costs and make ASP a very attractive enhanced oil recovery method provided the consumption is not too large and the alkali can be propagated at the same rate as the synthetic surfactant and polymer. However, the process is complex so it is important that new candidates for ASP be selected taking into account the numerous chemical reactions that occur in the reservoir. The reaction of acid and alkali to generate soap and its subsequent effect on phase behavior is the most crucial for crude oils containing naphtenic acids. Mechanistic simulation of the ASP flood considering the chemical reactions, alkali consumption, and soap generation and the effect on the phase behavior is the key to success of future field operations. Using numerical models, the process can be designed and optimized to ensure the proper propagation of alkali and effective soap and surfactant concentrations to promote low interfacial tension and a favorable salinity gradient. In this paper, we describe the ASP module of UTCHEM simulator with particular attention to phase behavior and the effect of soap on optimum salinity and solubilization ratio. Phase behavior data are presented for sodium carbonate and a blend of surfactants with an acidic crude oil that followed the conventional Winsor phase transition with significant three-phase regions even at low surfactant concentrations. The solubilization data at different oil concentrations were successfully modeled using Hand's rule. Optimum salinity and solubilization ratio were correlated with soap mole fractions using mixing rules. ASP coreflood results were successfully modeled taking into account the aqueous reactions, alkali/rock interactions, and phase behavior of soap and surfactant. Mechanistic simulations give insights into the propagation of alkali, soap, and surfactant in the core and aid in future coreflood and field scale ASP designs.
Development and production of coalbed methane involves the production of large volumes of water. The salinities and sodium adsorption ratios of coalbed methane (CBM) water from the Powder River Basin range from 370 to 1,940 ppm and 5.6 to 69 respectively. Surface discharge of CBM water can create serious environmental problems; subsurface injection is generally viewed as economically nonviable. It has been shown that oil recovery from reservoir sandstones can be improved by low salinity waterflooding for salinities ranging up to 5,000 ppm. There may be both technical and regulatory advantages to application of CBM water to oil recovery by waterflooding. Thin section and scanning electron microscope studies of the mineral constituents and distribution of Tensleep and Minnelusa sandstones show they are typically composed of quartz, feldspar, dolomite and anhydrite cements but have very low clay content. The sands contain interstitial dolomite crystals in the size range of up to about 10 microns. Three sandstone cores from the Tensleep formation in Wyoming were tested for tertiary response to injection of CBM water. The cores were first flooded with high salinity Minnelusa formation brine of 38,651 ppm to establish residual oil saturation. Synthetic CBM water of 1,316 ppm was then injected. Tertiary recovery by injection of CBM water ranged from 3 to 9.5% with recoveries for all but one flood being in the range of 5.9 to 9.5%. Previous studies showed that the presence of clay was needed for response to low salinity flooding. As a test of the recovery mechanism, a Tensleep core was preflushed with 15% hydrochloric acid to dissolve the dolomite crystals. The treated core showed no tertiary recovery or pressure response to CBM water.
CO2 flooding has become the fastest growing gas injection EOR method, contributing 4.8% of U.S. oil production. An integrated approach was undertaken to evaluate the CO2-EOR feasibility for Marathon's Rocky Mountain (RM) region assets. The RM assets of the Wind River and Big Horn basins were evaluated using detailed geological and compositional reservoir models imposed with multiple development scenarios. The fractured nature of the RM assets posed a challenge for reservoir modeling, which prompted combinations of approaches such as production ranking to facilitate fracture descriptions. Extensive laboratory CO2-oil PVT tests were also conducted to tune a representative equation-of-state fluid model to confidently quantify reservoir fluid behavior. CO2 injection scenarios for two oil fields were evaluated using compositional dual-porosity and dual-permeability reservoir models. Performance evaluation under multiple sensitivities, namely WAG ratio, fluid properties, injection pressures, and fracture characteristics were also investigated to quantify their impact on oil recovery factors. The simulation recovery results were non-dimensionalized to generate distinct type-curves, which were then applied to areas that have similar fracture and geological characteristics.
The unique workflows generated during this study were verified and benchmarked by using them to history match the performance of an analogous RM field currently under CO2 injection. This paper describes the integrated approaches applied to maturing RM assets, which in addition to identifying significant IOR potential, have helped enhance the reservoirs' characterizations, standardize subsurface workflows, aid facilities design, and scale-up performance data for optimal reservoir management.
1. Improved Oil Recovery
In 1978, the United States Congress commissioned the Office of Technology (OTA)(1) to evaluate the state of the art in U.S. oil production. The OTA concluded that the 300 billion barrels of known U.S. oil were economically unproducible by conventional methods in practice at that time. The OTA report also evaluated a range of enhanced oil recovery (EOR) techniques and their potential for improving the prospects of extracting a sizeable fraction of this known resource base. These major political and administrative amendments triggered increased interest in EOR in late 70's and early 80's, most notably in California and the Permian Basin of West Texas.
Now, 30 years later, there is again a strong interest in improving domestic oil production(2), which has been on a continuous decline of approximately 3% per year (Figure 1)(3), while the total ‘unproducible oil' referred to in the OTA report(1) has increased to a whopping 400 billion barrels(4). The U.S. Geological survey reported(5) that the bulk of the conventional oil yet to be produced in the world resides in already discovered reservoirs, with the ever decreasing possibility of finding newer reserves. The most important conclusion of this report, from an oil self-reliance point of view, is that the EOR techniques have not been tried for most of these reservoirs. Therefore, the potential for EOR applications in the U.S. is very large with a target of approximately 400 billion barrels(6).