Heavy Oil Pool Research Articles

Geological trends of occurrence of heavy oil pools in north-eastern part of Timan-Pechora Province

Geological trends of occurrence of heavy oil pools in north-eastern part of Timan-Pechora Province

Modelling and assessing the effectiveness of developing the Shumovskoye field

With the depletion of light oil stock, the heavy high-viscosity oil stock is rising. In this regard, there appear the technologies allowing to provide industrial levels of high-viscosity oil extraction. Therefore, the research of effective methods of developing heavy high-viscosity oil pools is one of the important development directions in the oil industry. One of the most cost-effective technology is non-stationary waterflooding (NW). There are currently not so many examples of using the technology of non-stationary waterflooding at the HVO pools. This is due to the fact that waterflooding as a development method has low efficiency at the HVO pools. The obtained results, based on modelling, showed that the technology of non-stationary impact is quite effective.

Geochemistry and origin of shallow gas in the Baise Basin, southern China

Abstract Many small and medium-sized Paleogene pull-apart basins in southern China contain an abundance of biogenic gas shows. Such shallow gas with biogenic characteristics has been thoroughly investigated only in Baise Basin. Hence, the research results from Baise Basin could serve as a model for the origin and characteristics of shallow gases in similar basins and areas in Southern China. There are ten gas fields with a total of proven reserves of 20 billion cubic meters discovered in Baise Basin. Three gas fields are located on the western and southern flank of the basin, and they are gas caps to heavy oil pools from depths between 600 m and 850 m. These accumulations contain dry biogenic gases, with C1/C1-5 exceeding 0.99, light δ13C1 (–76 to −54‰), and heavy δD1 (−218‰). Trace heavy gaseous hydrocarbons are strongly biodegraded (iC4/nC4>3). The other seven gas fields are located in the northern fault zone and the central Nakun uplift of the basin at depths between 300 m and 700 m. Gases are mainly unassociated and condensed gases. The condensed gases are depleted in 13C (δ13C1: −67 to −53.7‰, δ13C2: −52.3 to −36.1‰, δ13C3: −43.3 to −33.4‰), but wet with C1/C2+3 mostly less than 20, suggesting a mainly thermal origin at low maturity. The unassociated gases are dominated by methane, with C1/C2+3 ratio above 100, variable N2 (0 to 5.4%), and traces of CO2. The δ13C value of methane in the unassociated gases is between −76 to −60‰, and δD1 values from −248 to −213.7‰. These gases also contain isotopically light ethane with δ13C2 values of −64.5 to −42‰, which we infer to have originated from deeper horizons as a result of migration or diffusion from low-maturity thermal gases with light stable carbon isotopic compositions (C1/C2+3 <20, δ13C2 from −60‰ to −58‰). A similar thermal origin is inferred for the other heavy gaseous hydrocarbons. Formation water with the shallow gases of this basin is mainly NaHCO3-type with low TDS ranging from 1000 to 4500 ppm. The (HCO3+CO3)/Cl ratios range from 1.5 to 100, indicating a relative open hydrodynamic condition and the possible intrusion of meteoric water. These data indicate that early biogenic gas generated syndepositionally was probably not preserved, and that the current biogenic gas accumulation formed mainly as a result post-depositional of crude oil biodegradation in the western basin and coal biodegradation in the northern fault zone. Shallow gases in Baise Basin are mainly secondary biogenic gases, with an admixture of low maturity thermogenic gases from deeper horizons.

A New SAGD-Well-Pair Placement: A Field Case Review

Summary Steam-assisted gravity drainage (SAGD) has been improved consistently by experimenting with various solutions in both oil sands and heavy-oil fields in Canada (Butler 1994; Singhal et al. 1998). The SAGD process consists of two stacked horizontal wells and is proven technology in heavy-oil fields (Butler and Yee 2000). Employing the same concept of gravity drainage, SAGD-well placement convention has been revisited and challenged many times (Birrell and Putnam 2000; Edmunds 1991; Parappilly and Zhao 2009). Known to the industry, the cross-SAGD (also called XSAGD) (Stalder 2007) and J-shaped well steam-assisted gravity drainage (JAGD) (Larter et al. 2008) processes are two examples of fit-for-purpose well design and recovery schemes that require unique drilling practices. The Celtic pool, located in Lloydminster, Saskatchewan, is an active Husky Energy Incorporated (Husky) thermal field that includes 31 SAGD well pairs. In this heavy-oil pool, one of the SAGD well pairs (I3/I4; Well I3 as producer and Well I4 as the injector) experienced production downtime soon after coming into service. Following numerous unsuccessful service jobs, several re-entry options were suggested in order to recover remaining reserves. These included sidetracking Well I3, redrilling a new well from the same pad location, or commencing a new well from a different surface location. These cases were ranked, and in 2010, on the basis of a drilling-risk assessment, the new horizontal producer well (I3A) was drilled close to the existing well pair. Well I3A was placed counter currently below the existing injector well (I4) and set successfully parallel to the abandoned Well I3. Steam conditioning was completed in the first quarter (Q) of 2011, and the new SAGD well pair (I3A/I4) has been put on production successfully. The new well pair was positioned in the opposite direction of a conventional SAGD-well-pair placement. This paper presents the original I3/I4 pair performance, the challenges, results of redrilling Well I3A, reservoir-simulation study, and recent field production of the I3A/I4 SAGD well pair.

Genetic types and distribution of shallow-buried natural gases

Great volumes of shallow-buried (<2,000 m) natural gases which are mainly composed of biogases and low-mature gases have been found in the Mesozoic-Cenozoic sedimentary basins in China. Many shallow gas reservoirs in China are characterized by coexistence of biogas and low-mature gas, so identifying the genetic types of shallow gases is important for exploration and development in sedimentary basins. In this paper, we study the gas geochemistry characteristics and distribution in different basins, and classify the shallow gas into two genetic types, biogas and low-mature gas. The biogases are subdivided further into two subtypes by their sources, the source rock-derived biogas and hydrocarbon-derived biogas. Based on the burial history of the source rocks, the source rock-derived biogases are divided into primary and secondary biogas. The former is generated from the source rocks in the primary burial stage, and the latter is from uplifted source rocks or those in a secondary burial stage. In addition, the identifying parameters of each type of shallow gas are given. Based on the analysis above, the distributions of each type of shallow gas are studied. The primary biogases generated from source rocks are mostly distributed in Quaternary basins or modern deltas. Most of them migrate in watersoluble or diffused mode, and their migration distance is short. Reservoir and caprock assemblages play an important role in primary biogas accumulation. The secondary biogases are distributed in a basin with secondary burial history. The oil-degraded biogases are distributed near heavy oil pools. The low-mature gases are widely distributed in shallow-buried reservoirs in the Meso-Cenozoic basins.

Delineation of a sandstone-filled incised valley in the Lower Cretaceous Dina-Cummings interval: implications for development of the Winter Pool, west-central Saskatchewan

Abstract Major heavy oil deposits are present in Lower Cretaceous strata of west-central Saskatchewan. The Winter Heavy Oil Pool (approximately 566 044 mmbl) consists of bitumen-rich sands from the Aptian–Albian Dina and Cummings members of the Mannville Group. This succession unconformably overlies Paleozoic carbonates and is conformably overlain by the Lloydminster Member. Lower Cretaceous deposition in the Winter area was influenced by topography on the regional sub-Cretaceous unconformity, including the Unity uplands south of the study area and major paleovalleys opening to the northwest. The overall depositional framework consists of a lowstand and transgressive fluvial sandstone deposit (Dina Member) that evolved into a brackish embayment system (Cummings Member). Upon sea level fall, a valley was incised into the mudstone-dominated marginal marine deposits, which filled with sandstone during a subsequent sea-level rise (Cummings Member). Exploitable heavy oil reservoirs are contained within these incised valley sandstone beds. Further transgression led to a rising water table with widespread deposition of an organic-rich shale and coal followed by marine shale of the Lloydminster Member. The new depositional model for the area should lead to more optimal placement of horizontal wells in the reservoir, which is vital to continued bitumen extraction from the Winter Pool.

Polymer Flood Application to Improve Heavy Oil Recovery at East Bodo

Abstract The East Bodo, Lloydminster SS heavy oil pool has been exploited using primary recovery and waterflood. IOR screening showed that a polymer flood would be a preferred IOR technique. Subsequent coreflood tests indicated that the polymer flood could recover 20% OOIP incremental oil, after waterflooding, to a 95% water cut. Data gathered from the coreflood was used to fine tune the reservoir simulation model to help design the pilot and predict potential economic reserve capture for a commercial field-wide polymer flood. Subsequently, a pilot was initiated. During the pilot operation, achieving the target polymer viscosity, dependant on water quality, proved to be a significant challenge. Early field response is being observed through an increase in injection pressure, reduced water cut and polymer breakthrough. Further positive response of this polymer pilot allows for the expansion of the polymer flood technology to other parts of this reservoir; some with bottomwater and gas cap. This paper reviews the progress of the East Bodo polymer flood, from laboratory concept to working field application, in four major steps:IOR screening using simulations and coreflooding,field pilot design/implementation,pilot performance, andnext steps. Introduction Pengrowth has targeted East Bodo (Alberta side) and Cosine (Saskatchewan side) for waterflood optimization and subsequent enhanced oil recovery applications. Currently, the most practical EOR technology for this heavy oil reservoir seems to be the polymer flood technology in combination with horizontal wells. Several investigators(1–4) have demonstrated the potential of the polymer flood technology for improved oil recovery in heavy oil reservoirs. The East Bodo/Cosine Reservoir produces from the Lloydminster Formation, which is part of the Lower Cretaceous Mannville Group. Pengrowth provided some of the reservoir characteristics, as summarized in Table 1. This particular reservoir is separated into two parallel lobes trending North/West to South/East. To complicate matters, local gas caps are found primarily on the Saskatchewan side of the reservoir. Thus, the current waterflood patterns are located on the Alberta side. In the future, optimized waterflood and EOR schemes need to include those parts of the reservoir which are overlain by gas caps or influenced by bottomwater. A plan of progression aligned with the priorities of Pengrowth was laid out as follows:Optimize existing waterflood;Step out waterflood into limited gas cap areas;Then, target areas with a more extensive gas cap;Determine enhanced waterflood potential, for instance polymer flood; andArrange well patterns to benefit both waterflood and subsequent EOR process. IOR Screening Several IOR technologies were considered for application in the East Bodo Field. What follows is a list of IOR processes that were initially considered, but screened out after technical or economical issues could not be overcome.Thermal Recovery: Pay is too thin - heat loss to overburden is too large; oil not viscous enough to form a stable steam chamber; fireflood has potential, but a previous pilot on a neighbouring McLaren pool yielded poor results.

Understanding the Enigma of Reserves Growth: The Whys

Abstract It is a common claim that reservoir engineers and geologists are too optimistic and overestimate reserves. To evaluate this claim, a total of 493 reservoirs of light/medium oil, heavy oil and gas were tracked over a period of more than 40 years, compiling Alberta Government records estimating ultimate recovery from 1961 to 2002. Recovery factors, well counts, actual production/injection data and implementation of improved recovery schemes were also tracked to determine the reasons for reserves growth. In addition, the effect of price on growth of reserves was also examined. Contrary to the claim, the study actually shows remarkable reserves growth in light/medium oil pools discovered in the 1950s. It was found that ultimate recoveries from over 73% of the light/medium oil pools were underestimated and that growth above the initial recovery estimates occurred. The light/medium oil pools averaged a 97% growth in reserves. Because of the mature state of depletion and extensive production history, we can see that the cumulative oil and gas produced to date is often well above the original ultimate recovery forecasted by earlier conservative techniques. Similar growth trends were discovered for heavy oil and gas pools discovered prior to the 1980s. Heavy oil pools averaged a phenomenal 1083% growth in reserves while gas pools averaged 86%. Light/medium and heavy oil pools tended to grow both in recovery factor and volumes in place (OOIP). Gas pool reserves grew mainly by volumes in place (OGIP). Although reserves growth phenomena have been studied before, this paper discusses the causes of reserves growth and shows the critical importance that improved recovery schemes, infill drilling information and new technology have on this growth. In conclusion, reservoir engineers and geologists are, if anything, too conservative in their estimates of ultimate recovery, although their production rate predictions may be overly optimistic. Introduction Interest in reserves growth is gaining momentum as petroleum experts around the world speculate on remaining oil and gas reserves. Additional reserves come not only from discovery of new pools, but also from existing pools. Currently, the majority of reserves additions arise from known resources. Many factors contribute to reserves growth which, to this point, have never been evaluated for the province of Alberta. In this paper, we attempt to understand not only the enigma of reserves growth and the reasons behind it, we also attempt to determine the main characteristics of reserves growth in Alberta based on the analysis of data obtained from the Alberta Energy and Utilities Board (AEUB). Background/Literature Review The oil and gas industry is widely divided with respect to reserves and their growth and there is an extensive body of research and literature on this issue. This review focuses on Canada and the United States. In the United States, Arrington(1) was the first to recognize the significance of reserves growth. He developed a methodology for estimating reserves growth in fields that are missing reserves data for the early years after discovery. Arrington found these ultimate recovery estimates useful for predicting the results of exploration programs and as a valuable management tool.

Origin of the Neogene shallow gas accumulations in the Jiyang Superdepression, Bohai Bay Basin

Natural gas resources occur extensively along the east coast of China, with a number of large and medium-sized gas fields being discovered in recent years. Gas reservoirs include Neogene, Paleogene and the underlying Mesozoic and Paleozoic basement. Of the total proven natural gas reserves in the Jiyang Superdepression, Bohai Bay Basin, almost 89.7% is present in the shallow Neogene gas pools, in traps formed on top of the paleotopographic highs and along the margin of the secondary depressions. These gases are closely associated with heavy oils, occurring as gas caps or associated gases within the heavy oil pools, or in separate gas pools above, or updip from, the heavy oil pools. The gases contain over 95% methane and small quantities of C 2 + alkanes, nitrogen and carbon dioxide. The stable carbon isotopes of methane in these gases are up to 10‰ more positive than those of the thermogenic gases in the deep Paleogene reservoirs, with propane more enriched in 13C than butane. This study demonstrated that the majority of the petroleum source rocks in the Jiyang Superdepression tend to be oil-prone, and are currently within or shallower than the conventional oil window (0.45–1.0% Ro). The chemical and carbon isotopic compositions of the gases, together with the moderate to severe biodegradation of the associated heavy oils in the shallow Neogene strata, clearly suggest that the formation of the shallow natural gases in the Jiyang Superdepression result from the anaerobic degradation of accumulated oils in reservoir.

Simulated Production Behaviour of Heavy Oil Pools With Gas Caps

Abstract A number of thin heavy oil pools in Western Canada are being produced in which gas coning is unavoidable, even with long horizontal wells. The petroleum literature tends to have an abundance of cases where there is an associated gas cap over a thick, low viscosity oil leg that can theoretically be produced without appreciable gas coning. Gas/water coning evaluation is often restricted to the analytical calculation of breakthrough times and critical coning rates. Thus, work in the literature has limited applicability in thin oil columns of heavy oil pools. This paper reviews the unique production characteristics of those pools where gas coning is typical and discusses the underlying reservoir mechanisms associated with that production signature. In the case of a thin heavy oil pool, there may exist four distinct periods during a well's life. The first period is pre-breakthrough, the next is post-breakthrough where there is a rising gas-oil ratio, then a period identified by a decreasing gas-oil ratio and, finally, a period of relatively flat gas-oil ratio. Wellbore dynamics, standoff distance, gas cap thickness and areal extent, oil zone thickness and drainage area, vertical and horizontal permeability, oil viscosity, solution-gas oil ratio, and relative permeability all combine to control the production signature. Introduction Historically much of the literature(1-11) dealing with coning has focused on critical coning rates and breakthrough time, but very little discussion has been devoted to post-cone breakthrough response. There are many situations where production rates must exceed critical coning rates to be economic. This is particularly true in reservoirs with thin oil columns. Although horizontal wells may increase oil recovery and decrease GOR production signatures in thin oil columns, they generally cannot totally alleviate gas/water coning. TABLE 1: Summary of layer properties in reservoir model. Available in Full Paper. This paper investigates the behaviour of heavy oil pools in which small gas caps exist. One very unusual characteristic of these pools and drive mechanism is that gas-oil ratio (GOR) may decline with time or pressure depletion. This is in contrast to solution gas drive systems or in large gas cap reservoirs where, for the large majority of project life, the GOR is increasing. This work uses simulation as a tool to understand oil production and GOR profiles. Description of Simulation Model Simulations were performed for a horizontal well on 400 m spacing. The objectives of the simulations were to predict GOR behaviour in horizontal wells and to examine the sensitivity of the GOR profile to: gas cap vs. no gas cap, gas cap size, oil viscosity, pay thickness, etc. A 40 ? 21 ? 6 grid was used, representing a 800 m ? 399 m ? 4 m volume of reservoir. A uniform area grid was used. All grid blocks had areal (xy) dimensions of 20 m ? 19 m. The thicknesses (z) of the grid blocks were 0.8 m for the top layer and 0.64 m for the remaining five layers. Tables 1 and 2, as well as Figures 1 and 2, show the reservoir and model parameters.

Groundwater Development For the Oil Industry

Abstract Water is used as a resource for the drilling of oil and gas wells, drilling camps, secondary recovery methods (water and steam flooding), and permanent facilities such as compressor stations and batteries. Traditionally, water has been hauled, pumped from surface water bodies, or pumped from wells drilled by a water well contractor. Just as the oil industry uses professionals for the location of drilling sites using tools such as mapping, surface and. borehole geophysics, aerial photography, and satellite imagery, so does the hydrogeologist/groundwater engineer. In addition, groundwater supplies are evaluated by the hydrogeologist/groundwater engineer for yield and longevity as would be the case in a completed oil or gas well. Also, as in petroleum exploration, there are Governmental rules and regulations to contend with in groundwater exploration and development. Economic considerations playa major role in deciding upon the use of groundwater as a source from the point of risk, capital, and maintenance costs. This. paper provides an overview of the decision making processes employed to minimize the risk associated with groundwater development, and the methodologies employed to maximize the success of constructing a low cost, minimal maintenance, and dependable groundwater supply. Introduction Water supply in the oil industry is a high priority for a number of applications from the start of exploration through to enhanced recovery, as well as requirements for potable supplies in camps and permanent facilities. However, it is quite common in the oil industry to plan for exploration drilling and development of ancillary facilities without any consideration for the water supply. Water supply consideration usually occurs when it becomes apparent that there is no water. The first thought that usually comes to mind is to "take some water out of the creek." This reaction at first seems reasonable as one can actually "see" the water. If there is no surface water to be "seen," then it is quite common to call up a water hauler. In some cases, a driller may be called upon to dig a water well, perhaps even a water well driller may be contacted. In many instances, the loss or interruption of a water supply can shut down a very expensive operation. For this reason, a low cost, minimal maintenance, and dependable water supply is required. This paper will detail the methodology and benefits of developing such a water supply utilizing groundwater. In the past, a relative surplus of under-developed surface and groundwater sources in Western Canada saved many projects from floundering due to lack of water. The future may not be so kind. A recent study by the National Energy Board(2) indicated there may be as many as 246 potential new waterflood projects in light oil pools, 156 projects in heavy oil pools, and 48 potential steam injection projects in the Western Canada Sedimentary Basin, representing over 200 million cubic metres of oil. This will conservatively translate into a future incremental demand on the Western Canada industrial water budget of in excess of 200 million cubic metres.

Horizontal Wells: Successes And Failures

Introduction To date, about 6500 horizontal wells have been drilled around the world in various field applications. In Canada alone, about 750 horizontal wells were drilled from 1988 until 1992. In 1993, about 700 horizontal wells were estimated to be drilled in Canada(1,2). Thus, a large amount of data exists to review the field performance of horizontal wells. The objective of this article is to briefly review the field applications of horizontal wells under various reservoir conditions, especially for Canadian reservoirs. A review of economically successful and unsuccessful wells is used to develop a list of important parameters that need to be considered for selecting commercially successful applications of horizontal wells. Field Applications To date, horizontal wells have been used in naturally fractured reservoirs to enhance well productivity by intersecting natural fractures. Moreover, horizontal wells have also been used in oil reservoirs to minimize water and gas coning, and in gas reservoirs (with bottom water) to minimize water production. Additionally, in Canada alone, over five hundred horizontal wells have been drilled in high permeability, heavy oil reservoirs. Horizontal wells have also been used in low permeability gas reservoirs to enhance drainage volume and therefore, to enhance cumulative gas production per well, so as to make them economic. Horizontal wells have also been used in thermal oil recovery(3), not only to produce highly viscous bitumen in the Cold Lake area(4), but also to produce heavy oil in the Tangleflags North area(5). Other applications of horizontal wells include miscible flooding in the Keg River and Pembina Nisku reef reservoirs to produce a thin oil zone sandwiched between the top solvent zone and the bottom water zone(6,7). Recently, horizontal wells have also been used in waterflood applications. Relative to oil applications, only a few gas production wells are drilled horizontally, probably due to low gas prices over the past few years. Recently, in Canada, horizontal wells have also been used in gas storage reservoirs to enhance short term productivity to meet peak gas demand. The main applications in Canada are significantly different from those in the U.S. In the U.S., out of about 4500 wells, over 2500 horizontal wells were drilled in the low permeability Austin Chalk formation and about 200 wells have been drilled in the fractured Bakken Shale formation. The objective here was to intersect natural fractures and improve well productivity. In the U.S., except in Alaska, California, and the Gulf-coast, very few horizontal wells are drilled for water and gas coning applications. Thus, the typical U.S. application is for a low permeability, naturally fractured formation. In contrast the majority of Canadian applications are for water or gas coning situations. Almost 45% of the Canadian wells to date have been drilled in heavy oil fields in Saskatchewan and Alberta. About 40% of the wells have been drilled in medium to light oil fractured carbonate reservoirs in Southeastern Saskatchewan. Several heavy oil pools with bottom water zones (which could not be produced economically using vertical wells) have been made economic by drilling horizontal wells.

Development of Pelican Lake Area Using Horizon1tal Well Technologies

Abstract CS Resources has been a pioneer in the use of horizontal wells to develop heavy oil reservoirs. From 1988 to 1991, CS Resources drilled, and currently operates, 17 horizontal wells in a thin, heavy oil pool in the Pelican Lake area in northcentral Alberta. The horizontal wells were drilled in three phases; eight wells, in 1988, five wells in 1989/1990 and four wells in 1991. At each phase of development, well costs improved and productivities increased. The continual improvement in the overall performance and cost effectiveness of the project can be attributed to the focused approach CS Resources takes toward pool development. This paper will discuss the aforementioned phases of development and how knowledge gained from each phase was used to improve performance in subsequent phases. Several significant accomplishments will also be discussed, including:The drilling of the first ever lateral arm off of a horizontal well in Canada.The drilling of an experimental "J" type profile (in an attempt to improve pump performance).The drilling of a horizontal well with a horizontal length/vertical depth ratio believed to be greater than that of any other well ever drilled. Introduction Most of the vertical wells at Pelican Lake had been shut in due to uneconomical Production. In January 1988 when the first eight horizontal wells were drilled in Pelican Lake, Very few horizontal wells have been drilled in Canada. Some discussion of the first eight Well phase is given in References (1) and (2). Use of horizontal well technologies has turned the Project into a technical and economic success a success which can be attributed to CS Resources focused approach To pool development approach used us comprised of three key components:RESEARCH-Considerable technical work was completed prior to each phase of development.COMMITMENT-Some of the first wells drilled sis not perform as well as predicted. The reasons for the under performance were investigated and the project has since become a success.COMMUNICATION-Discussion throughout the project between geology, drilling, reservoir and production disciplines as well as field staff and service companies, has improved overall project understanding. It has also lead to continual cost and productivity improvements. History The Pelican Lake area is located 175 miles north of Edmonton, Alberta (Figure 1). The discovery well, Gulf Pelican 6-9-81-22W4, was drilled in 1978. The main oil bearing formation is the Wabiskaw "A" which has an average net oil pay of 5.0m. The PI gravity of the oil is 14', and the viscosity is between 600 and 100 centipoise at 20 ºC. Formation Sand has an average porosity of 26 and an average horizontal permeability of 3 darcies. During October 1987, CS Resources entered into a farm-out and option agreement with Gulf Canada covering 58 square miles in the Pelican Lake area. Prior to CS Resources acquisition of the subject lands, more than $100 million had been expended in the Pelican Lake area. From 1980 to 1986, approximately 100 vertical and deviated wells were drilled.

In Situ Combustion Tests On Eyehill Cummings Reservoir

Abstract In early 1984, a series of four combustion tube tests were performed at The University of Calgary on restored cores from the Eyehill Cummings heavy oil pool, located near Lloydminster, Saskatchewan. The tests provided a useful comparison of normal vs enriched air in situ combustion. Important observations arising from this test series were:water injection decreased the oxygen requirements;increased oxygen enrichment resulted in increased oxygen storage in the swept zone behind the combustion/ rant; andwater injection resulted in an increase in (swept zone) oxygen storage. The dry enriched air test showed some oxgyen breakthrough near the end of the test which resulted in an increase in viscosity of the produced oil. Increased sulphate levels in the produced water during that test also reflected the oxygen breakthrough. Introduction In recent years, laboratory combustion tube tests have become the customary method of determining the feasibility and the design parameters of an in situ combustion project. These tests, which utilize oil and homogenized core from the proposed reservoir, provide a relatively inexpensive method of predicting the type of problems which will be encountered in the field. They also give a qualitative indication of the "burn" performance of a specific reservoir, because it has been found that the results from one reservoir are rarely applicable to another. In addition to providing the air or oxygen and fuel requirements for an in situ combustion project, combustion tube tests also determine the properties and compositions of the produced fluids (oil, water and gas). Moore, el at. (1984) showed that the burning mode (low or high temperature oxidation) and the location of the burn front could, to some degree, be inferred from the composition of the produced gases, as well as by the viscosity and asphaltenes content of the produced oil and the pH and sulphate ion concentration of the produced water. In 1984, Murphy Oil Company and the Canadian Government's Department of Energy, Mines and Resources (EMR) contracted with the In Situ Combustion Research Laboratory at The University of Calgary to perform four combustion tube tests using core,oil and brine from the Eyehill Cummings heavy oil pool. This research group, located in the university's Department of Chemical and Petroleum Engineering has conducted over 230 such tests on over 50 different reservoirs world wide. This paper summarizes the results of the series of four combustion tube tests and compares the combustion process characteristics in various operating modes. Experimental Equipment The core holder used for this test series was a 10 cm (4 in.) diameter, 1.83 m (6 ft) long thin walled (1 mm) Type 600 Inconel tube. The tube was wound with twelve 1000 W heaters, forming twelve heating zones, each 15 cm (6 in.) in length, thus allowing for near adiabatic operation of the combustion test. A thirteenth heater was wound around the injection end of the tube to aid the ignition process.

Sedimentology and Ichnology of Shallow-Water Deltaic Complex: Lower Cretaceous Sparky Formation, Wainwright Heavy Oil Pool, Alberta, Canada: ABSTRACT

Much of the 2.5 billion bbl of recoverable reserves in the Lloydminster heavy oil area lie within the Sparky Formation. In the Wainwright pool, the Sparky is 20-30 m thick and comprises three stacked parasequences interpreted to have formed during progradation of a shallow-water deltaic complex into the Cretaceous epicontinental Boreal Sea. Two 4 to 7 m-thick coarsening-upward parasequences comprise the lower Sparky member and are interpreted as progradational, brackish-water, delta lobe deposits. Intensely bioturbated prodelta mudstones grade up into delta-front siltstones/very fine sandstones, which contain low-angle stratification (HCS.), graded-laminated storm beds, and convex ripples, capped by abundant fair-weather wave ripples. Shoaling is reflected in the vertical succession of ichnofacies: Zoophycos(.)-Cruziana-Skolithos-Psilonichnus. Each parasequence is truncated by a flooding surface and overlain by a thin transgressive shale unit deposited within a bay following lobe abandonment. The 10 to 15 m-thick upper Sparky parasequence exhibits a complex three-dimensional arrangement of mudstones, siltstones, sandstones, and coals and is interpreted to have formed in a mosaic of bay, marsh, and swamp environments on the lower delta plain. Following abandonment of the entire deltaic complex, peat-forming environments were established resulting in the formation of a regionally extensive 2 to 3 m-thick coal seam that capsmore » the Sparky succession. Delta-front sublitharenites were cleaned, sorted, and laterally redistributed by storm processes, and form better reservoir facies than feldspathic litharenites of the distributaries.« less

Modification Of A Downhole Gas Burner For Successful Ignition In A Low-Pressure Heavy Oil Reservoir

Abstract Ignition problems were encountered with a downhole gas burner for initiating a fireflood in a low-pressure depleted heavy oil reservoir. The gas burner design was modified and tested for two air injection rates at the National Research Council of Canada. A better split of the air flow and mixing with the fuel gas, as well as improved flame stabilization were provided in the modified burners. Successful ignitions were achieved in the Husky Tangle fags Fireflood Project in the Lloydminster area. Introduction Husky Oil Operations Ltd. has been conducting thermal recovery pilots in the Lloydminster heavy oil pools for some twenty years. Cyclic steam stimulation and steamflood pilots have been more successful than fireflood pilots, but the latter is a potential recovery process for the extensive heavy oil resources in thinner formations. Development of fireflood recovery technology is continuing in the Tangleflags Fireflood Pilot in Saskatchewan, northeast of Lloydminster (Fig. 1). The pilot was initiated in 1984 with three 12.1 ha, inverted seven-spot patterns and six offset wells, as shown in Figure 2. The wells were completed in the General Petroleum (GP) Formation (a type-log is shown in Fig. 3). In 1985. the injection well 4C7-13 was auto-ignited by steam and air injection. This pattern has been performing well with extremely good oxygen utilization. The other two injection wells, A6-13 and A7-13, were ignited successfully in 1985 with downhole natural gas burners, but poor oxygen utilization in both patterns forced their shut-down in October 1985 and August 1986, respectively. The performance of the gas burner ignitions and the producers were examined. Poor burner ignition in a low-pressure depleted reservoir was cited as a major reason for the poor oxygen utilization. Similar ignition problems were encountered in the low-pressure depleted reservoir at the Husky Golden Lake Sparky Fireflood Project. It was concluded that the gas burner design should be modified for re-ignition in the Tangleflags pilot and to meet the commitment of continuing development of the fireflood technology. The operation of the existing gas burner was reviewed at the Gas Dynamics Laboratory of the National Research Council of Canada (NRC) in Ottawa. A design program was initiated to modify the burner for operation at the 500 and 1000 kPa reservoir pressures in the Tanglefiags Pilot. A modified burner was built and evaluated at NRC. Using the modified burner, injection well A6-13 was ignited in June 1986. The burner was further modified at NRC for a lower air injection rate in A7-13, which was also successfully ignited in November 1986. Good oxygen utilization was subsequently achieved in both patterns. Burner Design Flame Stability and Ignition Considerations A flame is secured in a stream of combustible gases when the burning velocity SL of the mixture equals the local gas velocity U. When either one of these quantities exceeds the other, instabilities due to blow off or flashback of the flame are experienced. The burning velocity depends on the initial pressure, temperature, and composition of the combustible mixture, and its maximum value is usually realized close to the stoichiometric mixture ratio.

Formation conditions for heavy oil pools and possible hydrate formation in the northeastern part of the Timan-Pechora province

Formation conditions for heavy oil pools and possible hydrate formation in the northeastern part of the Timan-Pechora province

Waterflood Behaviour of the Low-Gravity Wainwright Pool

Abstract This paper outlines the development and performance of the Wainwright fieldin east-central Alberta, where the Wainwright sand produces 20–22-gravity oilfrom a depth of approximately 2,100 feet. The field was the first heavy oilpool in Alberta in which pressure maintenance by waterflooding was undertaken.Although pressure maintenance has been in progress for only three years, theperformance during this period is indicative of the project's success. To forestall the adverse effects of rapid pressure decline and increasinggas-oil ratios in this solution gas drive reservoir unitization as aprerequisite to full-scale pressure maintenance was instituted. The field wasunitized as five separate units, with pressure maintenance conducted by two operators. To the end of 1965, the cumulative oil production from the field wasapproximately 8,600,000 barrels. In December, 1965, oil production was 4,560barrels per day, with pressure maintenance accounting for approximately 70 percent of this. The ultimate recovery (primary plus waterflood) for the field hasbeen estimated at 31,300,000 barrels, which is more than double the recoveryanticipated by natural depletion. Introduction The Wainwright Sand reservoir is located on the southwestern flank of theheavy oil region of east-central Alberta. This is shown in Figure 1. Thefield was the first heavy oil pool in Alberta in which pressure maintenance bywaterflooding was undertaken. The reservoir was developed on 20-acre spacing, and the unitized areas include 202 producing wells. Reservoir characteristicsare included in Table I. The reservoir has a gas cap and an aquifer. During primary depletion, itproduced principally as a solution gas drive reservoir with some gas capexpansion. This was evidenced by rapidly declining reservoir pressures andincreasing gas-oil ratios. Although some water was produced from down-dip wellsalong the southwest rim of the present producing limits, and there was anoticeable encroachment of water before unitized operations began, there was noappreciable recovery resulting from the water influx. Early in 1959, it wasobvious that the natural energy of the reservoir was going to produce only asmall fraction of the original oil-in-place.