Development Of Carbonate Reservoirs Research Articles

Physical Simulation of Colayer Water Flooding in Low Permeability Carbonate Reservoir in Middle East

To study the flow mechanism under different displacement modes of low permeability carbonate reservoir in the Middle East and to improve the utilization of various types of reservoirs, the physical simulation experiments of water flooding by different displacement methods were carried out. Selecting two types of rock samples with different permeability levels, two-layer coinjection and separated production experiments by samples I and III and conventional water flooding experiments by samples II and IV were carried out. In addition, by using low magnetic field nuclear magnetic resonance, the development effect of microscopic pore structure under the different injection-production models was analyzed. Results show that, compared with the coinjection, the recovery rate of sample I was higher than II, 19.30%; sample III was lower than IV, 23.22%; and the comprehensive recovery degree reduced by 3.92%. NMR data also show that the crude oil is mainly distributed in the large pore throat; after water flooding, the displacement is also within the large pore throat, whereas the small pore throat is mainly obtained by the effect of infiltration absorption. The above studies provide a laboratory basis and foundation for the further development of low permeability carbonate reservoir in different Middle East strata.

Paleogeomorphology restoration and the controlling effects of paleogeomorphology on karst reservoirs: a case study of an ordovician-aged section in Tahe oilfield, Tarim Basin, China

The Tarim Basin is the largest petroliferous basin in northwestern China and contains the Tahe oilfield, the highest hydrocarbon enrichment in the entire basin. Paleogeomorphology has important controlling effects on carbonate reservoir development. Using core data, thin sections and drilling, logging and seismic data, paleokarst was identified and analyzed. The paleogeomorphology of the top low-middle Ordovician was recovered following a comprehensive utilization of the impression and residual thickness methods in combination with unconformity identification. Based on the filling thickness and residual thickness, the karst paleogeomorphic units were classified, and their controlling effects on reservoirs analyzed. The second-order paleogeomorphic units primarily include four types: karst highland, karst gentle⁃slope, karst steep⁃slope and karst basin. The karst gentle⁃slope and karst steep⁃slope are further classified quantitatively into third-order paleogeomorphic units (monadnock, tableland, karst terrace and trench). The results show that the development of the karst reservoir differed in different geomorphic units. In the karst gentle slope, the favorable areas for karst reservoir development are the karst terrace, tableland, monadnock, and the ends and flanks of trench. In the karst steep⁃slope, the karst terrace and tableland are favorable areas. In the vertical vadose and phreatic zones of the gentle-slope region, a large number of caves and underground river systems developed, but in the steep-slope region, only a small number of shafts and isolated caves are observed. This study plays an important role in oil and gas exploration and development.

Long-core experimental study of different displacement modes on fractured-vuggy carbonate reservoirs

It is difficult to utilize real fractured–vuggy carbonate cores to conduct long-core displacement experiments due to the special structures of fractured and vuggy. Aiming to not affect the porosity and permeability of the original core structure, a special filling method on the sunken space of the core surface was created to meet the requirements of long-core experiments. Long-core experiments of depletion drive, water flooding, gas drive, and water alternating gas (WAG) drive were performed to simulate the actual conditions of one-dimension oil reservoir and systematically study the influence of different development approaches on the recovery of vuggy carbonate reservoirs. Results show that the optimal conversion pressure of water flooding is between 80% bubble point and bubble point pressure. In the high-pressure and high water-cut stage, the development effect of gas–water alternative drive becomes significant, it can effectively reduce water cut and improve oil recovery. The most suitable and effective displacement mode is adopted depletion drive first and converts water flooding when the pressure decreases between 80% bubble point and bubble point pressure. When the water cut approximately reaches 80%, then WAG flooding is performed. The experiments provide data and technical support for the rational development of vuggy carbonate reservoirs.

Origin of deep carbonate reservoir in northeastern Sichuan Basin: New insights from in-situ hydrothermal diamond anvil cell experiments

In situ Raman analysis on the segregated near-equilibrium carbonate-fluid interaction at elevated temperatures (room temperature−260 °C) and pressures (13-812 MPa) in a hydrothermal diamond anvil cell (HDAC) reveals the preservation mechanism of porosity in deep carbonate reservoirs in the northeastern Sichuan Basin. The carbonate-fluid interaction was investigated by separately heating carbonate minerals and rocks with four different acid solutions (saturated CO2 and H2S solutions, HCl, CH3COOH) in a sealed sample chamber. A minor continuous precipitation with increasing temperatures and pressures was observed during the experiments which caused minor sample volume change. The closed system is a preservation of pores and burial dissolution may not be the dominant diagenesis in the origin of porosity. Thin section photomicrographs observations in Changxing and Feixianguan Formations demonstrate that eogenetic pores such as moldic or intragranular pores with late small euhedral minerals, intergranular, intercrystal and biological cavity pores are the main pore types for the reservoirs. Early fast deep burial makes the porous carbonate sediments get into the closed system as soon as possible and preserves the pores created in the early diagenetic stage to make significant contribution to the deep reservoir quality. The anomalous high porosity at a given depth may come from the inheritance of primary pores and eogenetic porosity is fundamental to carbonate reservoir development. The favorable factors for deep reservoir origin include durable meteoric leaching, early fast deep burial, early dolomitization, etc. This deep pores preservation mechanism may be of great importance to the further exploration in deep carbonate reservoirs in the northeastern Sichuan Basin.

Study on gas-liquid relative permeability experiments of fractured-porous reservoirs

Abstract For carbonate reservoirs, gas-water and oil-gas relative permeability curve are of importance for parameters calculation in oil-field development, dynamic analysis and numerical reservoir simulation. The oil-gas/gas-water relative permeability curves were measured with unstable method under normal temperature and low pressure, using fifteen artificial fractured cores. The shape and change characteristics of gas/water and oil/gas relative permeability curve were mainly analyzed. The results showed that for the relative permeability curve of water driving gas. The saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency has a good power-function relation with core permeability. In addition, the saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency will decrease with the increasing of core permeability. However, for oil-gas relative permeability curves, the saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency will increase with the increasing of core permeability. It should be noted that the gas relative permeability presents a straight line in the normalized relative permeability curve, which indicates that the main flow is dominated by fracture with low displacement efficiency. The research results provide theory basis for fracture-vuggy carbonate reservoir development and new research idea for the further study of this kind of reservoir.

Production Characteristics with Different Superimposed Modes Using Variogram: A Case Study of a Super-Giant Carbonate Reservoir in the Middle East

Heterogeneity of permeability is an important factor affecting the production of a carbonate reservoir. How to correctly characterize the heterogeneity of permeability has become a key issue for carbonate reservoir development. In this study, the reservoirs were categorized into four superimposed modes based on the actual logging data from a super-giant heterogeneous carbonate reservoir in the Middle East. A modified permeability formula in terms of the variogram method was presented to reflect the heterogeneity of the reservoirs. Furthermore, the models of oil production and water cut were established and the analytical solutions were obtained. The calculation results show that the present model can predict the productivity of wells with different heterogeneous layers more accurately and rapidly. The larger the varigoram value, the stronger the heterogeneity of the reservoirs, and the faster the decline of production owing to a quicker reduction of formation pressure. With the increase in variogram value, the relative permeability of the oil phase is smaller and the water phase larger, and the water cut becomes larger. This study has provided a quick and reasonable prediction model for heterogeneous reservoir.

Ecological and economic aspects of by-pass water deposits use in the eastern oil region of Ukraine

Formulation of the problem. Oil deposits in the eastern region of Ukraine are confined to the upper zone of the lower hydrogeological floor (zone of stagnant regime). This zone lies at depths from 1.5 to 5.5 km, including most of the Paleozoic deposits, is characterized by the development of primary pore sandy-aleuric and cavernous-fractured carbonate reservoirs with high porosity and permeability in which broaching systems of formation, massive-reservoir and massive reservoirs are filled with sedimentogenic brines.Most of the deposits are depleted or are being developed in the final stages, in which, along with oil, there is also by-pass water in the extracted fluid.Factors affecting the environment during oil production are considered. The schemes of by-pass water impact on the environment are given.Results. In the article w show the urgency of stratal water use as hydromineral materials. Bromine, iodine, lithium are the main chemical components whose content defines water as a valuable raw material. Practical use of stratal water in Ukraine will increase the mineral resource base and reduce the impact on the environment.The authors analyze stages of the field development in terms of the extracted fluid water content. The water coefficient in produced fluid extracted on the oil field is the main element that increases the cost of oil. In the article the theory using stratal water is presented, which allows the transfer of these waters expenditure component in revenue.The authors describe theoretically "perfect" conditions in which the oil companies developing oil fields will work with profit. There are basic parameters that influence the overall profit of the company in terms of water production formation and considers in detail the income and expense components.Scientific novelty and practical significance. The article compares profitable work of the oil company without implementing related-field water as raw hydromineral. The authors graphically expressed how oil companies can increase their profits by using stratal water and keeping on development period. The paper determines that concentration of chemical components in water is the main indicator showing possible industrial development and building price on hydro- raw materials.

Theoretical innovation and technical progress will usher in a production period of gas fields with an annual capacity of ten billion cubic meters

Challenged by the increasing complexity of targets and the tense situation of turning losses into profits during the 12th Five-Year Plan, by virtue of technological innovation, Sinopec Southwest Oil & Gas Company proposed the theories of gas exploration in continental clastic rock and marine carbonate rock, and developed the development technologies for reef, channel sandstone and tight sandstone reservoirs. Moreover, it innovatively formed a series of engineering technologies, including intelligent sliding sleeve staged fracturing, blasting–packing–fracturing stimulation, impulse fracturing, and drilling, completion and production technologies for ultra-deep horizontal wells with high sulfur contents. With these innovated theories and improved technologies, great discoveries have been made in the continental clastic rocks and marine carbonate rocks in West Sichuan Basin, the marine shale in South Sichuan Basin, and the marine carbonate rocks in Yuanba area of NE Sichuan Basin, and three 100 billion-m3 class commercial gas reserves zones were discovered. Moreover, two medium- and large-sized gas fields were proved, and three medium- and large-sized gas fields were completely constructed. Both reserves and production reached a new record in history. During the 13th Five-Year Plan, Sinopec Southwest Oil & Gas Company will focus on the exploration and development of deep marine carbonate reservoirs, commercial development of deep shale gas, safe development of gas fields with high sulfur, and enhancement of recovery in mature gas fields. By the end of the 13th Five-Year Plan, it is expected that the annual gas production of (10–12) × 109 m3 will be achieved.

The Research of Reservoir Earthquake Prediction Based on the Design of Horizontal Well of Thin Carbonate Reservoir of J2 Gas Reservoir in Lingyinsi Structure

Compared to clastic rocks, the exploration and development of thin carbonate reservoir are 1more complex. Especially, the thin reservoir demands high resolution of seismic data. So the conventional methods are difficult to good exploration at the present time. According to the complexity of thin carbonate reservoir, we comprehensively analyze reservoir geology, logging and seismic response, combine natural gamma inversion, velocity inversion with porosity inversion for prediction of reservoir and obtain precise quantitative earthquake prediction. The analysis demonstrates the reliability of seismic reservoir prediction applied to design for horizontal well. On the basis of understanding the basic geological characteristics of the reservoir, this thesis takes the design for horizontal well of J21 for example, completes two sets of designs for horizontal wells group by combining prediction technology for reservoir seismic with geologic steering technique and greatly improve the drilling rate for thin reservoir.

Development of complex layered and fractured reservoir models for reservoir simulation

The link between the geostatistical modeling of multiscale carbonate heterogeneities and representative simulation flow models remains a challenge because conventional upscaling procedures often disregard the complex dynamic behavior that links the geostatistical static properties, dynamic rock/fluid data and reservoir operational conditions. This work proposes a methodology to build robust simulation models for naturally fractured carbonate reservoirs with multiscale geological characterizations. The development of this work follows three main steps: (1) hierarchical upscaling procedure by flow units, (2) integration of flow units into a reservoir-scale simulation model, (3) validation of simulation model. The hierarchical upscaling procedure was applied to three inter-well regions and extrapolated to three flow units. The proposed workflow is applied to a reservoir based on a combination of real and synthetic data from a Brazilian offshore carbonate reservoir. The methodology shows several advantages: it represents static and dynamic behavior from multiscale heterogeneities in reservoir simulation; it minimizes risk in the selection of well position and completion through well characterization of representative static and dynamic data for each flow unit; and, improved selection process for the simulation flow model. The methodology shows that the relative permeability defined in reservoir simulation can be different from the laboratory measured curve because it needs to match the dynamic behavior from the reference solution. This result shows that a proper characterization and upscaling approach are crucial to sufficiently represent geological heterogeneous scenarios in reservoir simulation. The methodology we present here is useful for multidisciplinary areas of expertise as it ensures the appropriate link between the fine scale geomodelling and the coarser scale reservoir simulation, considering the development of complex carbonate reservoirs.

No-Damage Stimulation By Use of Residual-Free Diverting Fluids

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177495, “No-Damage Stimulation Based on Residual-Free Diverting Fluid for Carbonate Reservoir,” by Y. Shi, X. Yang, F. Zhou, Y. Gao, S. Lian, X. Li, and X. Han, Research Institute of Petroleum Exploration and Development, CNPC, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed. Horizontal wells and acid stimulation are essential technologies for the development of complex carbonate reservoirs. However, conducting effective stimulation in horizontal wells with long intervals is extremely difficult because traditional acid systems can flow only into the high-permeability formations, leaving the damaged formation untreated. This paper studied three residual-free fluid systems for acid treatments and fracturing in order to develop no-damage or reduced-damage and highly effective stimulation techniques for long-interval wells. Introduction Horizontal wells are essential for the development of carbonate reservoirs in China. However, horizontal wells always have long intervals, so they are extremely difficult to stimulate. The fluid systems used are a critical aspect of high-efficiency stimulation. Traditional acid systems, which do not have diverting capabilities, can flow only into the high-permeability formations, leaving the damaged formation untreated. That is why long-interval wells with high heterogeneity need to be treated by a diverting acid system. A new diverting acid system should have the following characteristics: The capability to reduce the acid/rock reaction rate; a diverting performance to achieve uniform stimulation in a carbonate reservoir with high heterogeneity; and use of clean chemical additives to eliminate or limit damage. This paper analyzes three clean fluid systems for acid treatment and fracturing. The no-damage stimulation systems considered are a temperature-controlled deep-diverting acid system (TCA), a pH-controlled self-diverting acid system (DCA), and a fracture-reorientation technology using degradable fiber (RDF). TCA Diverting Mechanism of TCA. The TCA system is similar to ordinary gelled acid during pumping. The gelling agent can dissolve in water in a short time, reducing the frictional resistance of the system dramatically and making it easy to prepare and pump. At formation temperature, the system has a high viscosity to ensure diverting and retarding performance. After the acid fracturing treatment, the viscosity of the spent acid decreases in order to flow back easily and leave no damage in the formation.

Major factors controlling the development of marine carbonate reservoirs

Abstract Through case study of reef-shoal, karst and dolostone reservoirs in the Tarim and Sichuan Basins, the material base and the mechanisms of porosity creation, modification and preservation of carbonate reservoirs were examined carefully in order to figure out the major factors controlling the development of various types of carbonate reservoirs. Three factors control the development of carbonate reservoirs: (1) carbonate sediments of reef-shoal facies are the material base for not only reef-shoal reservoirs, but also dolostone and karst reservoirs; (2) epigenetic environment is crucial for porosity creation, i.e. reservoir space in ancient carbonates includes primary depositional porosity and/or secondary dissolution pores caused by epigenetic, freshwater dissolution; and (3) burial environment is the setting for porosity modification and preservation. There is no carbonate reservoirs of solely one origin, carbonate reservoirs are all the products of the combined effect of the above three factors. The four main controlling factors, reef-shoal sediments, epigenetic karstification, evaporation facies belt and burial-thermal fluid dissolution give rise to the reef-shoal, karst, sedimentary dolostone and burial-hydrothermal alteration dolostone reservoirs respectively.

Unconformities and their influence on lower Paleozoic petroleum reservoir development in the Tarim Basin

Abstract Ten regional unconformities punctuate the Lower Paleozoic carbonate succession of Tarim Basin. They can be divided into three orders and include four unconformity types. According to their extents and intensities of development, they can be categorized into three orders, a first-order unconformity of great lateral extent and depth of erosion, and second-order and third-order unconformities of lesser extent and erosional intensity. From the viewpoint of their origins, these unconformities can be classified into four types, structural unconformities, long-term exposure unconformities, synchronous sedimentary exposure unconformities and superimposed unconformities that include combinations of the previous three types. Through analyses of the geographic distribution of unconformity types across the geographic extents of the 10 unconformities and their temporal evolution, it was determined that unconformities of various orders have different effects on the development of carbonate reservoir beneath these unconformities. First-order and second-order unconformities are prominent in the development of karst reservoir of the Tarim Basin. Periodic exposure of carbonate rocks which occurs during erosion that generated third-order unconformities contributed to the development of multiple karst intervals. In addition, the abundance and size of karst intervals in progradational strata increased during sea level falls. Origins of unconformities control scales and types of karst reservoirs. Tectonic (angular) unconformities developed during tectonic uplift and denudation, which controlled the development of weathering crust karst reservoirs within zones containing buried-hill (e.g. low paleo-uplift). Long-term exposure (parallel) unconformities formed during long-term sea level fall which controlled the development of regional interlayer karst reservoirs within the platform. Synchronous sedimentary exposure unconformities formed due to intermittent exposure caused by sedimentary basinal infilling and subdued sea level fluctuations which controlled the development of penecontemporaneous karst reservoirs of smaller geographic extent along platform margins. Superimposed unconformities formed due to multiple superposed tectonic movements, which caused the superposition of multiple weathering crusts as individual karst reservoirs, or the stacking of karst reservoirs developed beneath different unconformity types.

Feasibility study on application of volume acid fracturing technology to tight gas carbonate reservoir development

Abstract How to effectively develop tight-gas carbonate reservoir and achieve high recovery is always a problem for the oil and gas industry. To solve this problem, domestic petroleum engineers use the combination of the successful experiences of North American shale gas pools development by stimulated reservoir volume (SRV) fracturing with the research achievements of Chinese tight gas development by acid fracturing to propose volume acid fracturing technology for fractured tight-gas carbonate reservoir, which has achieved a good stimulation effect in the pilot tests. To determine what reservoir conditions are suitable to carry out volume acid fracturing, this paper firstly introduces volume acid fracturing technology by giving the stimulation mechanism and technical ideas, and initially analyzes the feasibility by the comparison of reservoir characteristics of shale gas with tight-gas carbonate. Then, this paper analyzes the validity and limitation of the volume acid fracturing technology via the analyses of control conditions for volume acid fracturing in reservoir fracturing performance, natural fracture, horizontal principal stress difference, orientation of in-situ stress and natural fracture, and gives the solution for the limitation. The study results show that the volume acid fracturing process can be used to greatly improve the flow environment of tight-gas carbonate reservoir and increase production; the incremental or stimulation response is closely related with reservoir fracturing performance, the degree of development of natural fracture, the small intersection angle between hydraulic fracture and natural fracture, the large horizontal principal stress difference is easy to form a narrow fracture zone, and it is disadvantageous to create fracture network, but the degradable fiber diversion technology may largely weaken the disadvantage. The practices indicate that the application of volume acid fracturing process to the tight-gas carbonate reservoir development is feasible in the Ordovician Majiagou Formation of lower Paleozoic, which is of great significance and practical value for domestic tight-gas carbonate reservoir development and studies in the future.

A reserve calculation method for fracture-cavity carbonate reservoirs in Tarim Basin, NW China

Abstract To avoid big deviation in reserve estimation and make scientific and reasonable reserves to guide the exploration and development of fracture-cavity carbonate reservoirs, a new three-dimensional reservoir space description and reserve calculation method for layered, fracture-cavity carbonate reservoirs is used to calculate the reserves of X block in the Halahatang oilfield in the Tarim Basin. In the method, the reserve calculation parameters are worked out by quantitative spatial delineation based on high precision three-dimensional seismic data; the high confidence well-seismic inversion and sensitive attributes and threshold value are used jointly to delineate the oil-bearing area, effective thickness and effective porosity of the cavity, vug and fracture reservoirs. The reserves are calculated with the volumetric method, and the dynamic recovery of different types of reservoirs is calibrated by actual drilling data. This method is suitable for reserve estimation and development program making of fracture-cavity carbonate reservoirs with strong heterogeneity.

Study on the Stimulated Reservoir Volume Technology in Tight Carbonate Reservoir

In the development of carbonate reservoir, it usually uses acid fracturing to improve the production. Because of the limitation of, the production rates from the wells are very low. Based on the “stimulated reservoir volume” which is used in the development of unconventional reservoirs, combined with the characteristics of tight carbonate reservoirs, in the early stage with low viscosity liquid, large pump scheme, small size proppant and pulse type sand to form complex fracture network. In the later, with high viscosity liquid, high sand rate, large size proppant, and continuous type sand to enlarge the stimulated volume and conductivity. Based on the experimental evaluation, the fracture design was optimized, and it will provide a reference for the stimulation of tight carbonate reservoir.

Imaged-based multiscale network modelling of microporosity in carbonates

Abstract Diagenetic changes such as cementation or dissolution have a strong control on carbonate pore structure, and often disconnect the original intergranular pore space. Spatial distribution of submicron porosity (microporosity) that develops in the process, as well as its influence on flow properties, is difficult to image and characterize. Yet, a petrophysically rigorous pore-scale model that accounts for submicron porosity interconnectivity would help in the understanding and development of carbonate reservoirs dominated by microporosity. We present algorithms to geometrically match pore–throat networks from two separate length scales that can be extracted directly from three-dimensional (3D) rock images, or be constructed to match the relevant measured properties. We evaluate the combined influence of cementation and dissolution using a Bentheimer Sandstone sample, as well as image-identified microporosity on flow transport properties in an Estaillades Limestone sample.

Waterflooding Development of Fracture-cave Carbonate Reservoir

Reserving and flowing space of fracture-cave carbonate reservoir is a kind of large-scale Karst cave body, which is different with the space of normal sandstone reservoir or fracture-cave carbonate reservoir and which also displays particularity and complexity under normal seepage analysis methods during waterflooding development. The point that inflexion point of oil water rate with periodic oil production and inflexion point of oil water rate with water cut occur at the same time can be used as technical evaluation index in waterflooding replacing oil method. Multiwell unit waterflooding can be classified as pushing oil, replacing oil, and displacing oil.

Ordovician carbonate reservoir fracture characteristics and fracture distribution forecasting in the Tazhong area of Tarim Basin, Northwest China

Knowledge of fracture patterns is vital for Ordovician marine carbonate reservoirs in controlling the productivity of oil and gas wells. To improve the prediction of fracturing in favorable reservoirs, a range of relevant data was used, including fracture-system maps interpreted from seismic data, Ordovician top and bottom paleostructural maps, and cores obtained from 45 drill wells, to study reservoir characteristics and major controlling factors in the Tazhong area of the Tarim Basin. The effect of faulting on the development of fractures was assessed by a 3D finite element stress analysis that simulated paleostructural stress fields in the Middle Caledonian (the major fracture development period), using acoustic emission and rock mechanics data. The results show that fractures formed at a maximum effective principal compressive stress 47.9–62.4MPa (average 54.48MPa) in rock with tensile stress 4.10–8.02MPa (average 5.78MPa). Areas in potential reservoirs having the highest effective tensile stress were found to possess the most favorable fracturing pattern, distributed at the intersections of large faults in the immediate vicinity of fractured areas. This prediction matches field conditions more closely than previously reported, and provides new geological support for Ordovician fractured carbonate reservoir petroleum exploration and development in this area. The study also validates the methods of paleostructural stress field simulation for favorable area prediction.

Evaluation of Recovery Technologies for the Grosmont Carbonate Reservoirs

Summary The Upper Devonian Grosmont formation is a bitumen-saturated, carbonate unit located in Northern Alberta. It is considered to be among the world?s next largest unconventional oil resource plays. Since early 2006, there has been an increased interest in Grosmont resources exhibited by a range of companies, including super-majors. Several in-situ pilot tests were conducted in the central portion of this area in the 1970s and 1980s, using steam and in-situ combustion processes. Similar to field tests in the McMurray formation oil sands before invention of the Steam-Assisted Gravity Drainage (SAGD) process, none of the early recovery technologies tested proved to be economic. Because the "gravity" drainage process has proved successful in commercial development of the McMurray formation oil sands since the mid- to late-1990s, the recovery potential for the Grosmont formation should be re-evaluated, based on improved recovery techniques. Results from cyclic steam stimulation (CSS) field tests are compared and analyzed to understand the similarity and fundamental differences in reservoir properties between the McMurray formation oil sands and the Grosmont formation carbonate rocks. A preliminary interpretation is provided for laboratory test results for solvent processes applied to Grosmont carbonate cores. The scaling considerations from the laboratory results to field expectations are discussed. The paper also provides a direction for future studies and optimization opportunities for reservoir recovery leading to the commercial development of Grosmont carbonate reservoirs.