Vertical Sweep Efficiency Research Articles

Chemical Fingerprinting of Stratigraphic Surfaces to Refine Reservoir Architecture and Differentiate Fluid Flow Regimes: ABSTRACT

The variable development of depositional cycles within hydrocarbon reservoirs, especially reservoirs contained within platform carbonates, can have a profound influence on fluid flow. These cycles can be recognized in core and logs and should form the basis of subsurface geologic models. When placed into a sequence stratigraphic framework, cycle variability can be predicted. We herein investigate the use of chemostratigraphy to refine a reservoir-scale stratigraphic framework and demonstrate the influence of this framework on fluid flow. Using cores and outcrops of the Permian San Andres Formation in the Guadalupe Mountains of southeastern New Mexico, permeability distribution and waterflood response was modeled for a small-scale carbonate sequence (105 no thick) containing variably developed depositional cycles that formed in a carbonate ramp setting. Cross-sectional fractal permeability fields, used in simulated waterfloods, demonstrate sensitivities of oil recovery and overall injection rare to the stratigraphic framework. Major, minor and trace element variation measured on 44 interval composites from core, using a combination of techniques including inductively coupled plasma (ICP) and mass spectrometry, characterize and fingerprint important stratigraphic surfaces (sequence boundaries, cycle boundaries, and flooding surfaces). Less distinct cycles below this surface we characterized by compartmentalized flow and poor vertical sweep efficiency, whereas well-developed cyclesmore » above are characterized in our analog by a potential for early water breakthrough and relatively high vertical sweep efficiencies.« less

Prudhoe Bay: infill drilling in gravity dominated WAG floods

Abstract Many horizontal miscible gas floods experience relatively low vertical sweep efficiency due to gravity segregation of the injected solvent and reservoir liquids. This is true for the Prudhoe Bay Miscible Gas Project (PBMGP) in which the enriched-hydrocarbon miscible injectant (MI) is expected to sweep only approximately 300f the reservoir volume in the project areas. The Prudhoe Bay reservoir has a relatively thick oil column, high inter-sand vertical permeability, high net-gross, and is generally developed on 80 acre (324 = 103 m2) well spacing. An infill drilling project was implemented in the Northwest Fault Block (NWFB) area of Prudhoe Bay (Fig. 1) to improve solvent sweep efficiency and increase EOR reserves. This project differs from many EOR infill drilling projects in that most of the additional recovery is attributable to EOR, with minimal improvement in waterflood recovery. The infill project is feasible because the reservoir is relatively thick, and sufficient EOR reserves are obtained from miscible displacement around new injectors. A significant increase in flood rate can also occur, resulting in production acceleration. Results of the project will guide analysis of infill drilling in other EOR areas at Prudhoe. The Prudhoe Bay Miscible Gas Project is the world’s largest enriched-hydrocarbon miscible gas flood, and is located in northern Alaska, USA.

Steam-Foam Mechanistic Field Trial in the Midway-Sunset Field

Summary A one-pattern, steam-foam mechanistic field trial was conducted in Section 26C of the Midway-Sunset field (upper Monarch sand). The test objectives were (1) to understand the mechanisms of steam diversion caused by foam under reservoir conditions, (2) to establish whether foam can exist in-depth away from the injection well, and (3) to measure incremental oil that can be attributed to foam. Surfactant was injected with steam and nitrogen continuously, and bottom-hole injection pressure (BIHP) increased from 100 to 300 psig, indicating good foam generation. Better steam distribution across the injector's perforations occurred when foam was generated. Improvements in both vertical and areal sweep efficiency of steam were observed. Substantial temperature and gas saturation increases coincided with surfactant breakthrough and local reservoir pressure increases at observation wells. Complementary laboratory core-floods showed that foam generation could occur at low-pressure gradients, which are typical of in-depth conditions. Both laboratory and field data were interpreted as evidence that the in-depth presence of foam was the result of local generation wherever surfactant, steam, and nitrogen were present, rather than propagation of a foam bank generated near the injector. Some oil-production increase was also observed during the test; however, an accurate quantitative estimate of incremental oil owing to foam was difficult to establish.

A New Combustion Process Utilizing Horizontal Wells And Gravity Drainage

Abstract The Combustion Override Split-production Horizontal-well (COSH) process has been conceived to combine the high recovery potential of gravity drainage with the energy efficiency of combustion processes while minimizing problems associated with combustion operations. COSH should be less sensitive to oil composition and combustion kinetics and it has minimal water supply and disposal requirements. The mechanisms for the COSH process have been identified within the limitations of numerical simulation. A simulation study indicates that the COSH process has technical performance approaching that for the highly rated steam-assisted gravity drainage (SAGD) process, and has much lower energy costs. Introduction In-situ combustion has been studied and piloted for several decades because it has the potential of the highest energy efficiency and lowest production cost among thermal processes(1) Unfortunately, overall field experience has been disappointing because of numerous problems such as slow production response difficulty in sustaining combustion, early oxygen breakthrough, severe sanding, gas locking of down-hole pumps, corrosion, and scaling. The literature on combustion studies relates primarily to frontal displacement of the combustion zone. This involves linear or radial areal displacement from vertical injection wells to vertical production wells with the pay-zone visualized as being divided into successive zones including a combustion zone followed by a condensing zone and an oil bank which is displaced ahead of the combustion front. Many elegant and sophisticated studies have been conducted on the dynamics of the combustion process for linear displacement, particularly with combustion tubes(2). Unfortunately, it is very difficult to model in the laboratory the three-dimensional effects of gravity segregation of fluids and poor vertical and horizontal sweep efficiency which are at the heart of many of the problems in field combustion projects. It is also difficult to analyze the process mechanisms in combustion field projects which have been reported to increase oil production. In particular, for field projects it is difficult to determine the relative importance of thermal effects, gravity drainage (particularly in dipping reservoirs) and complex three-phase relative permeability effects caused by the large volumes of gas and water used. This paper will present a new approach to take advantage of the theoretical efficiency of combustion by combining the best features of successful steam pilots that the Alberta Oil Sand Technology and Research Authority (AOSTRA) has participated in while minimizing the negative features responsible for problems reported in earlier field combustion projects. COSH Process The main features in the Combustion Override Split-production Horizontal-well (COSH) process(3) are described as follows, with reference to Figures I and 2:Gas containing oxygen is injected via rows of vertical injection wells. The gas may be air, oxygen or recycled gas with oxygen added. The gas is generally injected in the upper part of the pay-zone. Maintaining continuous gas injection into the reservoir and cold water circulation within the wells will prevent combustion damage. The vertical wells can also serve to define the geology and locate the base of the pay-zone accurately prior to drilling the horizontal production well and they could be used to monitor temperature profiles in the lower part of the gas chamber with cemented-in thermocouples.

An Overview of Miscible Flooding

Abstract Introduction In most reservoirs, oil recovery can be improved by the implementation of an enhanced oil recovery (EOR) scheme. An EOR scheme can be classified as either a miscible or an immiscible process. In a water flood or an immiscible gas flood, the displacing fluid is not soluble in the displaced oil. The displacement results in a residual oil saturation due to the inter-facial forces between the displacing fluid and the displaced oil. In contrast, miscible fluids are soluble in oil so there will be no inter-facial force between oil and solvent and the theoretical residual oil saturation will be zero. Hydrocarbon miscible floods are the most common tertiary EOR schemes m Western Canada. They can be sub-divided into vertical or horizontal miscible floods. Vertical Miscible Floods Vertical miscible floods are usually implemented in pinnacle reefs or reservoirs with a high relief angle. The majority of Canadian vertical floods have been implemented in the Rainbow Lake, Brazeau River, Pembina/West Pembina, and Wizard Lake areas of Alberta. The solvent is injected as a blanket at the top of the reservoir to take advantage of a gravity stabilized displacement. Subsequent chase gas injection drives the solvent blanket downward. The highest wells in the structure are usually chosen as the injectors to maximize oil displacement and the producing wells are completed in the lowest porous interval above the oil water contract. Production rates are controlled to restrict solvent and water production. Horizontal wells are becoming popular in vertical miscible floods. These wells arc usually drilled as producers near the water/oil contact to reduce water and gas coning problems, and thus increase the production rate and reduce the sandwich loss. Innovative completion techniques such as perforation below or at the oil/water contact have also resulted in reduced sandwich losses. The expected incremental recovery compared to upward waterflood is in the range of 15–40%. The vertical solvent flood process develops a good volumetric sweep efficiency as a result of gravity stabilization of the interface, and is ideal in homogenous reservoirs. In heterogeneous reservoirs with horizontal shale barriers, a substantial reduction in oil recovery improvement can be expected as a result of poor vertical sweep efficiency (e.g. Golden Spike, Alberta). Horizontal Miscible Floods In horizontal miscible floods, solvent and water are injected alternately to mobilize residual oil and push it to the producers. After the injection of solvent and water, chase gas or leaner solvent (which is miscible with the solvent) and water are injected to extend the solvent bank size and complete the displacement process. After injection of 25%–40% hydrocarbon pore volume (HPV) of solvent and chase gas, the process reverts to horizontal water flood to depletion. In other words, in the early stage of the miscible project, oil is replaced by miscible solvent and moved toward producing wells. Later, residual solvent is mobilized by chase gas and moved to where it can contact more residual oil. Through this process, an expensive commodity, residual oil, is replaced by a cheaper commodity, chase gas.

Modeling Reservoir Heterogeneity Within Outer Ramp Carbonate Facies Using an Outcrop Analog, San Andres Formation of the Permian Basin

Variably cyclic, fusulinid-rich, outer ramp facies of the Permian San Andres Formation are exposed along the Algerita escarpment, Guadalupe Mountains, New Mexico. We have used the outcrop exposures and cored wells drilled adjacent to the outcrop to assess reservoir- and interwell-scale variability of permeability as a potential analog for carbonate reservoirs in the Permian basin and elsewhere. Permeability distribution was evaluated using a field permeameter and conventional measurements on small core plugs taken along vertical and horizontal outcrop traverses and from the slim-hole cores. Permeability is related to the variable development of depositional cycles within a small-scale sequence and also to diagenetic overprinting. Geostatistical models of permeability variation, honoring the geologic and petrophysical data, were constructed and input into a waterflood simulator to understand the interactions between heterogeneity and flow. Variograms constructed from conventional plug analyses of permeability for a vertical outcrop transect contain a significant small-scale signal (noise), as seen in the high nugget effect (approximately 50% of the overall sample variance), and have correlation ranges of less than 4.5 m (15 ft). Different vertical variogram characteristics are displayed by cyclic and less distinctly cyclic parts of the San Andres. Variograms constructed for horizontal transect data from three distinct stratigraphic units have nearly identical properties. Overall, the ranges of correlation are short (3-3.5 m; 10-12 ft) when compared to typical interwell distances, supporting a nearly uncorrelated and highly variable permeability model. Using observed short ranges of vertical and horizontal correlation and honoring the vertical transect data, cross sectional, conditionally simulated permeability fields were generated and used in simulated waterfloods to investigate the sensitivities to an oil recovery model and overall fluid injection rate for this style of stratigraphy and cyclicity. Cyclic parts of the section are characterized by a potential for early water breakthrough and relatively high vertical sweep efficiencies. Within the less distinctly cyclic section, waterflood fronts have a fingerlike profile and vertical sweep efficiency is generally poorer.

How to Waterflood Reservoirs With a Water Leg

Abstract Waterflooding oil reservoirs with an underlying water zone is often problematic because the injected water can channel into the water zone, Yet such reservoirs constitute a large resource in Alberta and Saskatchewan. This research was directed toward reducing water mobility in the bottom water zone for more efficient waterflooding. Three novel approaches were tested: the Emulsion Slug Process (ESP), the Alternating Water-emulsion (AWE) Process, and the Dynamic Blocking Procedure (DBP). All three methods result in an improvement in the vertical sweep efficiency and involve the injection of polymer or emulsion, with water. In each case, there are two modes: blocking and displacing. The differences among these processes lie in the application of the two modes. In ESP, the blocking and displacing modes are used only once with the blocking agent injected first, followed by a waterflood. In the AWE process, the two modes are performed alternately. While in DBP, the two modes are performed simultaneously. Experiments conducted in this study showed that by using a suitable mobility control agent in DBP, a noticeable increase in both oil production rate and ultimate oil recovery was realized. The opposite may occur for the wrong choice either of the mobility control agent, or of the approach. The experimental results are presented, with a discussion of the roles of mobility control and blocking agents. Introduction Waterflooding oil reservoirs with a water leg (i.e., a communicating bottom water zone) are usually inefficient due to the flood water channeling into the bottom water zone. This problem was first recognized in the early sixties when Barnes(1) suggested the use of a viscous water slug as a mobility control agent to lower the WOR. Since then, the use of various chemicals such as polymers and emulsions, has been proposed as mobility control and blocking agents to improve waterflood performance(2–4). However, none of these studies accounted for crossflow between the oil and bottom water layers when planning a chemical augmented water-flood. Other studies have shown that cross flow plays a major role in waterflood performance in layered reservoirs(5–10).Thus, a systematic way of utilizing a chemical or an emulsion as a blocking agent under bottom water conditions accounting for crossflow is required for efficient displacement of oil. In this paper, the Emulsion Slug Process (ESP), the alternating Water-emulsion (AWE) Process, and the Dynamic Blocking Procedure (DBP) are discussed. Emulsion Slug Process (ESP) The main objective of the three processes proposed in this paper is to try to isolate the bottom water zone when displacing oil by water. An emulsion is used as a blocking agent to increase the flow resistance of the bottom water zone. In the Emulsion Slug Process, the blocking mode is performed once at the beginning, followed by a waterflood. Under bottom water conditions, the flow resistance of the oil zone is much higher than that of the bottom water zone, i.e., Ro > > Rw where Ro and Rw are the flow resistances of the oil zone and water leg respectively; thus, the WOR will be high at the beginning of the flood.

Design of a Gravity Assisted Immiscible Gas Injection Program For Application In a Vuggy Fractured Reef

Abstract The potential of gravity assisted immiscible gas injection was evaluated for a waterflooded vuggy fractured reef. Extensive laboratory work was carried out for the study of the effects of wettability and heterogeneities on recovery. Tests were performed on 2-D glass micromodels, unconsolidated systems and reservoir core plugs. The recovery due to gas injection was correlated to the recovery due to waterflooding for each test. The laboratory results indicate that an incremental recovery of up to 20% original oil in place (OOIP) should be expected from gas injection even from a heterogeneous fractionally wet formation. In this paper, an overview of the laboratory and preliminary design work is presented. A discussion of the mechanisms that take place during the gravity assisted immiscible gas injection in a fractured vuggy reservoir with fractional wettability is also included. Introduction Gas injection is the oldest of the fluid injection processes. The intention of recent gas injection projects has been to increase the ultimate recovery and therefore gas injection can be considered an enhanced oil recovery process. Gas injection may be either a miscible or an immiscible displacement process. In this paper only immiscible gas injection is considered. Of particular interest to this work is the immiscible injection gas in the carbonate reefs of Western Canada. The primary problems with gas injection in carbonate reservoirs(1) are the high mobility of the displacing fluid and the wide variations in permeability. Much greater control over the injection process must be exercised than is necessary with waterflooding. The benefits obtained by the gas injection are dependent upon horizontal and vertical sweep efficiency of the injection gas. The sweep efficiency depends oil the type of porosity system present and on the gasflood design. In general, immiscible gas injection better suited to vertical displacement schemes than horizontal displacement schemes. Oil fields that have low oil saturation in either primary or secondary gas cap are prime candidates for improved recovery by gas injection into the gas cap(1). Further shrinkage of oil is reduced by gas injection. Inasmuch as it maintains a relatively high pressure gradient in the oil phase, relative permeability to oil remains high and oil is produced faster and in greater quantity. Considerable insight and a large number of demonstration experiments dealing with the use of gravity assisted immiscible gas injection (GAIGI) as a novel EOR process is given in Kantzas et al.(2, 3) and in Chatzis et al.(4). In these references description of the pore level mechanisms are given and extremely high recoveries of waterflood residual oil are reported for unconsolidated systems. Also high recoveries are reported for Berea sandstone. It was explained that when oil spreads on water, the invasion of gas displaces residual oil from large pores in water-wet systems. This oil forms a thin film which becomes thicker as the displacement evolves. An oil bank is finally formed which flows downwards and sweeps the reservoir. This approach extends gas injection strategies to reservoirs which are too shallow for miscible floods. Also it avoids the use of any expensive surfactant systems.

The Evalua1Ion Of Cyclic Steam Sltimulation Of An Oil Sand Reservoir Using Post-Steam Core Analysis

Abstract A post-steam core was recovered from a Cold Lake area oil sand reservoir subjected to cyclic steam stimulation. The objective of the program war to recover competent core from a steamed portion of the reservoir and, via detailed core analysis, determine the effect of steam injection on the deteriorating productivity levels experienced at the pilot test wells. The core was successfully retrieved by sidetracking from an existing expendable wellbore which had received four cycles of steam injection. The coring program was accomplished at a cost considerably less than that of a new well. Core recovery war satisfactory at 84%, considering the approach used. Mineralogical analyses performed on the recovered core provided an improved understanding of the recovery mechanisms involved in steam stimulation of the reservoir, Some of the major findings were: 1. Vertical sweep efficiency was determined to be 60%. 2. Mineral reactions were confirmed and found to be a factor responsible for decreased absolute permeability. 3. The dissolution of feldspar may have contributed to suppressing the degree of swelling clay formation. 4. Thin impermeable calcite layers within the reservoir contributed to steam confinement within specific zones. These observations helped to explain the production performance recorded at the test wells and the knowledge was adapted to the development of future thermal operations at the pilot. Introduction Reservoir sweep efficiency is an important parameter to determine when evaluating a cyclic steam process. Conventional methods generally used to estimate sweep efficiency include observation wells, temperature logging, seismic profiling and post-recovery coring. Observation wells can be risky because they may not intersect the steamed zone. When the steam zone reaches an observation well, vertical sweep efficiency can be estimated from temperature logs run in the well, Temperature logs, however, have been shown to overestimate the thickness of the steam swept zone as a result of profile smearing(1). Seismic profiling can provide 3-dimensional seismic images which can be used to track the movement of induced heat fronts(2). This technology is relatively new and very expensive; these aspects tend to preclude its use in thermal projects. The most accurate method of determining vertical sweep efficiency is by extracting post-steam core(s) from a steamed portion of the reservoir. This is the only method that can provide tangible evidence which accurately reflects the portion of the reservoir actually swept by steam. Another important factor associated with cyclic steam stimulation is the effect of steam injection on the mineralogy of the reservoir(3–6). Perhaps the greatest benefit of obtaining a post-steam core is the opportunity to provide unequivocal mineralogical evidence concerning the defects of steam injection on the reservoir mineralogy. Such information could also provide a valuable test for geochemical models that utilize produced fluid compositions from thermal recovery projects to monitor mineral reactions occurring in situ(7, 8). This paper will deal with how a post-steam core program was used to provide the evidence necessary to help understand deteriorating productivity levels observed at an experimental cyclic steam pilot in the Cold Lake area of Alberta. A proprietary steam additive designed to control the swelling of smectitic clay minerals formed during steam injection was also being tested at the pilot in all attempt to limit reservoir damage that was believed to be occurring. Recovery and examination of post-steam core was necessary to confirm that reservoir damage had

Use of silica gel for improving waterflooding performance of bottom-water reservoirs

This research addresses the problem of waterflooding a medium-gravity of oil-bearing formation with a water leg, and offers recommendations for process selection. In many reservoirs the presence of a bottom-water zone results in a very poor areal and vertical sweep efficiencies. However, waterflooding still remains the most widely used oil-recovery technique for these reservoirs. Waterflood performance in these reservoirs can be improved greatly with effective methods of partially plugging the bottom-water zone. One such method is the use of CO 2-activated silica gel as a blocking agent in the presence of a bottom-water zone. Thirteen large-model experiments were conducted using silica gel, to study the effect of oil-to-water zone permeability contrast and thickness ratio, oil viscosity, and CO 2 injection. A qualitative comparison is made to show the relative merit of CO 2-activated silica gel injection among other mobility control agents. Several runs were conducted to study silica gel rheology both in presence and in absence of CO 2.

Major Influences of Clastic Reservoir Anatomy on Oil Recovery

Even in simple layer cake reservoirs, contrasting strata, pinchouts, and impermeable intercalations commonly impair vertical sweep efficiency. However, extensive impermeable streaks may prevent coning of water or gas. For many reservoir configurations, certain features can be either favorable or unfavorable for oil recovery depending on accumulation conditions, mobility ratio, structural dip magnitude and orientation, and applied drainage and injection schemes. Although this complicates relating classification systems of recovery efficiency directly to geological aspects, clastic reservoirs commonly display predictable production behavior closely related to environment of deposition. For example, fluid flow in deltaic reservoirs composed of sand bodies with contrasting permeabilities is dominated by pathways of least resistivity. These occur in typical patterns related to paleogeographical trends. The threat of local cusping, coning, and breakthrough of water or gas dictates careful planning of locations, completions and production levels of individual wells. Extreme anisotropy is often associated with low net-to-gross [open quotes]labyrinth[close quotes] reservoirs deposited in coastal plain environments. Overall connectivity may be attained at net-to-gross levels of between 0.3 and 0.4, but major vertical and lateral discontinuities will exist on a well-to-well scale. Sweep efficiency is strongly influenced by sand body trends relative to dip orientation, and specific well patterns aremore » required. Reservoir simulation input should preserve reservoir architecture and correctly incorporate no-flow boundaries and intercalations. Probabilistic modeling systems using representative sand-body geometry databases can provide estimate of connectivity and simulation input at an early stage of field development. The crux of the matter is the prediction of production behavior for alternative development plans to reduce the negative influences of reservoir heterogeneity.« less

Evaluation of the Potential Application on the Wag Process in a North Sea Reservoir

The paper discusses the potential increase in oil recovery due to injection of water alternating gas (WAG). The WAG process is compared to waterflooding and gas injection. The mechanisms of the WAG process which makes the process interesting for a North Sea reservoir are discussed. The application of a WAG scheme is discussed with regard to the field restrictions and possibilities of Norwegian reservoirs. The WAG process is found to improve the oil recovery primarily due to improved vertical sweep efficiency. Cross-sectional models have been used to study the sensitivity to variations in vertical permeability. The paper also reports results of multi-phase displacement experiments using sequences of gas and water injections. The oil recovery by primary and secondary injection of both gas and water have been measured both on Berea sandstone cores and sandstone reservoir cores. The measurements include experiments at realistic reservoir conditions using reservoir fluids, and also series of experiments performed at reduced pressure and temperature utilising model fluids.

頚城油田における水攻法評価 炭酸ガス攻法パイロットテストに向けて

A part of the reservoir in the Kubiki Oil Field has been waterflooded since 1980. Several producers already experienced water breakthrough to this date. In this situation, the project of CO2 flood pilot to this reservoir has been initiated and is in its third year at present.Three investigation wells have been drilled during the last two years in the pilot test area, and the information, such as full series of the state-of-the-art logging data, has been obtained to improve the geological and petrophysical description and to modify our understandings of the reservoir conditions after waterflood.Some conclusions of waterflood evaluation in the pilot area derived from the above mentioned investigations are as follows.• Good vertical sweep efficiency has been achieved.• Irreducible water has been displaced by injection water.• Oil saturation is reaching to residual oil saturation (20-30%) around the target area.• Secondary recovery is about 5% of OOIP while primary recovery was 15%.• Steep pressure gradient exists locally.• Rock facies varies vertically and/or horizontally in relatively small region.The whole above informations will be examined more minutely and merged for the better understanding of the reservoir conditions, which will contribute to design, performance prediction and evaluation of CO2 flood pilot.

Impact of Inducing Fractures at Prudhoe Bay

Summary Early step-rate tests (SRT's) on Prudhoe Bay water-injection wells showed that injecting cold (80 deg. F [27 deg. C]) seawater into the 200 deg. F [93 deg. C] Ivishak reservoir significantly reduced the formation fracture gradient. To understand the fracturing process, in-depth studies of field injection trends, innovative pressure-transient analyses of step-rate data, interpretation of specially designed injection-well tests, and several simulation studies were conducted. After evaluating the impact of formation breakdown on areal and vertical sweep and on oil production rates, we concluded that potentially negative effects from inducing fractures with clean-water injection into the Ivishak formation are minimal, while benefits include accelerated oil production. As a result, an injection pressure limit above the thermally reduced formation fracture gradient has been defined and adopted. Introduction The Prudhoe Bay oil field is on Alaska's North Slope. Rock quality in the Sadlerochit sand body, where the Ivishak sandstone is the main oil-bearing formation, is generally high, with permeabilities varying from 0.1 to 5 darcies [1.0 × 10–13 to 5.1 × 10–12 m2]. Production from the oil field is driven by a number of mechanisms, including gas-cap expansion, gravity drainage, miscible gas injection, and waterflooding. Waterflooding in portions of the Ivishak formation began in 1984. The waterfloods are generally peripheral pattern floods composed of variations of inverted nine-spot pattems with interwell distances of about 1,500 ft [457 m] (Fig. 1). Currently, water from two sources is being injected. Beaufort seawater will remain the primary water supply during the project's early years; loiter, however, reinjected produced water will become the main source. The seawater is heated to about 80 deg. F [27 deg. C] at the wellhead, compared with a produced-water temperature of 150 deg. F [66 deg. C]. During early pilot testing and in the months following waterflood startup, seawater-injection wells (SWI's) typically indicated formation breakdown during SRT's at injection gradients of 0.53 to 0.54 psi/ft [12.0 to 12.2 kPa/m]. Produced-water injectors (PWI's) showed higher initial fracture gradients, from 0.57 to 0.60 psi/ft [12.9 to 13.6 kPa/m]. The apparent reduction in fracturing pressure with lower injected-water temperatures caused concern regarding waterflood management. It was realized that injection at subfracturing pressures would result in severe underinjection in many waterflood pattems; conversely, if injection were to continue for an extended period at pressures above the fracture gradient, vertical and lateral fracture growth was possible. Because vertical and areal sweep efficiencies could be affected, an investigation of the fracturing process began. The approach involved reviewing injection data, analyzing pressure-transient step-rate data, designing and analyzing results from special well tests, and performing a variety of simulation studies. The objectives wereto identify fracture initiation pressures,to quantify the magnitude of fracturing and the impacts on flood performance, andon the basis of Objectives 1 and 2, to define a realistic injection strategy.

The Main Area Claymore Reservoir: A Review of Geology and Reservoir Management

Summary The Main Area Claymore reservoir (MACR) is the major reservoir of the Claymore field, located 110 miles [177 km] northeast of Aberdeen in U.K. Block 14/19, offshore North Sea. An integrated team effort by geologists, geophysicists, and engineers has led to an increase in recoverable oil for the MACR. Concurrently, the MACR production increased from 47 to 57 MSTB/D [7472 to 9062 stock-tank m3/d] from mid-1984 to the end of 1986. The MACR is of Late Jurassic Age. Fine- to coarse-grained sandstones of the Sgiath and Piper formations are succeeded by the very-fine- to medium-grained sandstones of the Claymore sandstone member (CSM) of the Kimmeridge clay formation. The CSM constitutes the bulk of the MACR and is divided into two informal reservoir units: the low gamma ray sands (LGRS) and the high gamma ray sands (HGRS). The principal early field problems were lack of sufficient pressure support, uneven water advancement in both the horizontal and vertical directions, and a large pressure gradient across the reservoir. Thus, more offtake and selective injection points were required to improve oil recovery. Growth of geological and engineering knowledge of the MACR has resulted from infill drilling and the integration of repeat formation tester (RFT) pressures, flowmeters, well logs, detailed core studies, and three-dimensional (3D) seismic. Increased current oil production and recoverable reserves are the consequences of this work. To improve oil recovery, a 10-slot subsea template for water injection was installed in Summer 1985. Three subsea water injectors have been drilled from this template and five platform wells redrilled as producers to downdip areas of the MACR. The recent drilling program owes its success to the combined efforts of a multidisciplinary team, which resulted in the optimum placement of wells and the adoption of selective completion to optimize areal and vertical sweep efficiencies.

Waterflooding Oil Reservoirs With Bottom Water

Abstract This research addresses the problem of waterflooding a medium gravity oil-bearing formation with a water leg, and offers recommendations/ or process selection. Many oil reservoirs in Alberta and Saskatchewan have some type of a high water saturation zone below the oil layer. The presence of a bottom-water zone results in very poor areal and vertical sweep efficiencies. However, waterflooding still remains the most widely used oil recovery technique for reservoirs with a bottom-water zone. The performance in such reservoirs can be improved greatly if an effective method of partially plugging the bottom-water zone can be developed. A possible means of accomplishing this would be to precede the waterflood with a slug of a mobility control agent. Recently(1) this possibility was investigated using a large flow model, for a series of mobility control agents, such as polymer, emulsion, air, biopolymer, and foam. The present study complements that investigation for a wider range of mobility control agent slug sizes, oil-to-water zone permeability and thickness ratios, etc. Also presented is a qualitative comparison of various mobility control agents to show their relative merits. The flow stability and displacement pattern are discussed jar each mobility control agent. It is shown that the choice of one agent over others depends on variables such as permeability contrast, relative oil-water layer thickness, etc. Introduction The problem of controlling mobility of water or gas has received attention for more than two decades(2–9). However, very few studies report a systematic comparative evaluation of various mobility control agents. In fact, some of these techniques have not been specifically tested for bottom-water cases. Only recently, slam and Farouq Ali(1) reported a systematic study of various mobility control agents available for improving oil recovery from a reservoir with a bottom-water zone. The present study complements the authors' previous study and gives new interpretation to various mechanisms involved in the process. Experimental Set-up and Procedure The experimental apparatus for the displacement tests consisted of a pump and an especially designed rectangular core holder. A constant rate, computer-controlled, positive displacement syringe pump was used along with floating pistons. The rectangular core holder had one inlet and one outlet at the inlet/outlet faces. Figure 1 shows a schematic of the experimental set-up. The core holder had a cover plate along the bottom side. This enabled one to pack several layers along the length. The chemicals used for different runs are listed in Table 1. Further details f the experimental procedure are available in References 1 and 10. Experimental Results and Discussion Displacement tests were carried out with water and different mobility control agents, viz. polymer, emulsion, air, foam, glycerine, etc. A total of 21 different runs were conducted to test the effectiveness of each of the mobility control agents with permeability, relative thickness and slug size as variables. These runs will be discussed under different sections according to the mobility control agent used. Table 2 lists major characteristics of different runs. FIGURE 1. Schematic of the experimental set-up. FIGURE 1. Available In Full Paper TABLE 1. Properties of chemicals used. Table 1 Available In Full Paper.

The Steam-Foam Process

Summary The steam-foam process was developed to improve the sweep efficiency of the steamdrive and steam-soak processes. Steamdrives that are not stabilized by gravity can have a poor vertical sweep efficiency as a result of (1) gravity overlay in a thick sand with vertical communication and/or (2) channeling in a layered formation with poor vertical communication between sand members. The reduced mobility of steam foam increases the pressure, and gradient in the steam-swept region to displace the heated oil better and to divert steam to the unheated interval. Surfactants reduce the steam mobility by stabilizing the liquid lamellae that cause some or all of the steam to exist as a discontinuous phase. The propagation of surfactant is retarded by ad sorption. In the phase. The propagation of surfactant is retarded by ad sorption. In the case of ion exchange of divalent ions from the clays, the surfactant is also retarded by precipitation and/or partitioning into the oil. The rate of propagation of foam is also determined by the mechanisms that generate and destroy foam. The generation mechanisms include leave-behind, snap-off, and division. The destruction mechanisms include condensation and evaporation, coalescence by a limiting capillary pressure, and coalescence resulting from the presence ofoil. The foam texture can be predicted from a population balance that includes these mechanisms. predicted from a population balance that includes these mechanisms. Introduction Scope. This paper reviews the steam-foam process. It is not an exhaustive survey of the literature, and I apologize to the many contributions that had to be omitted because of length limitations. The types of field application of steam foam are discussed first. Examples are taken from reported pilot results. The remainder of the paper focuses on process mechanisms. Understanding of the mechanisms for foam flow in porous media is still in the formative stage, and many advances can be expected. It is hoped that this paper will help the practicing engineer apply the process more efficiently and will challenge the researcher to advance the knowledge of the process and to develop more efficient formulations.

Enhanced Oil Recovery In Canada: Success In Progress

Abstract The oil industry in Canada has been in the forefront applying enhanced oil recovery technology. Fifty-one commercial projects were operating in 1987 in reservoirs producing light and medium** crude oil in Alberta. Several pilot projects are operating in Alberta. Saskatchewan and Ontario. This paper discusses enhanced oil recovery (EOR) in general and reviews the history of EOR application in Canadian reservoirs. The performance of several projects and the economic factors affecting EOR implementation are reviewed. Introduction Primary and secondary methods leave a substantial portion of oil unrecovered in the reservoir. Tertiary recovery, more often called enhanced oil recovery (EOR), can recover some of the oil left behind by secondary recovery methods. Field application of enhanced recovery in Canada dates from the North Pembina Cardium Unit hydrocarbon miscible pilot project in 1957–58. Fifty-one commercial projects are now operating, all of them hydrocarbon miscible floods in the Province of Alberta. Other EOR techniques are being or have been used in pilot tests, so far with limited or uncertain results. Is EOR successful? The performance and proliferation of projects affirms that additional oil is being recovered and that this additional oil recovery is economic. Oil Recovery Factors Affecting Oil Recovery Large volumes of oil will remain unrecovered after primary recovery, which uses the natural energy of the reservoir, fluid and rock expansion and water influx, to produce the oil. Recovery factors for primary recovery range from 0% to 50% of the oil originally in-place in the reservoir, averaging about 19%(1) for Alberta reservoirs. In some reservoirs, a portion of the oil not recoverable using primary recovery can be produced with secondary recovery methods, which involve adding energy to the reservoir to maintain the pressure by injecting a fluid, usually water or gas. Water injection is the most common secondary recovery method used to enhance oil recovery. Waterflood recovery factors range from 25% to 45% of the original oil-in-place (OOIP). For the waterfloods in Alberta, the average ultimate recovery factor is 32%(1). Approximately 20% of the total Alberta light and medium reserves will be recovered because of waterflooding. Water injection leaves oil in the reservoir as a residual saturation, trapped by capillary forces where the water has swept the reservoir, and at higher saturations where the injected water did not contact the oil. Waterflood displacement efficiency, or the portion of the original oil saturation that can be recovered from rock that is flooded by injected water, ranges from 40% to 70%. However, not all of the reservoir will be contacted by injected water. The water may be more mobile (less viscous) than the displaced oil, causing early water breakthrough and poor areal sweep. The water may be more dense than the oil and may tend to move to the bottom of the reservoir, reducing the vertical sweep. The combination of areal and vertical sweep efficiency is the volumetric sweep efficiency, which is the portion of the total reservoir volume that is contacted by injected water and which ranges from 20% to 90%.

Performance Monitoring And Reservoir Management Of A Tertiary Miscible Flood In The Fenn - Big Valley South Lobe D-2A Pool

Abstract In February 1983, a hydrocarbon miscible flood (HCMF) was Implemented in the South Lobe D-2A Pool, Fenn – Big Valley field in central Alberta. The pool had effectively watered out under the primary drive mechanism and its performance indicated a primary recovery of 48.8% of OOIP. Initial estimates suggested an incremental recovery factor of 15% by the tertiary flood. This paper presents the performance evaluation of the HCMF and shows how the derived information helped in a better management of the reservoir. Several techniques including analyses of radioactive tracers, and various logs aided in performance evaluation. Nine tracers were injected early in the life of the project to trace the movement of both injected solvent and water. To match the tracer response a computer model based on the work of Yuen et. al.(1) was utilized. The results provided useful clues about interwell reservoir characteristics, relative fluid velocity and reservoir sweep efficiency. In addition, important information about gravity override was provided by various production logs. The results of this evaluation indicated problems with early solvent breakthrough, and poor sweep efficiencies. Based on the results of different studies, the miscible displacement front is now being more closely managed by production adjustments to improve the areal sweep efficiency. Recompletions of injectors and producers improved vertical sweep efficiency and delayed solvent breakthrough. Introduction The Fenn – Big Valley South Lobe Nisku D-2A Pool is located approximately 160 km northeast of Calgary, as shown in Figure 1. The pool boundary and well locations are depicted in Figure 2. Development was carried out on a 16.0 hectare (ha) spacing with the drilling of 60 wells, 36 of which remained capable of production. Geological Description A detailed geological study of the pool was carried out in 1979. The study revealed that the pool consists of stratified porous dolomite ranging in thickness from about 19 m to 34 m. The reservoir is fairly heterogeneous in nature with significant variations in both porosity and permeability. Vertical continuity is blocked in some places by the presence of the Medial Dense or Duhamel Shale zones, which effectively separate the reservoir into two or three units. Within each unit, horizontal continuity is maintained by intergranular, moldic, and fracture porosity (short randomly oriented breccia fractures). All units are above the original oil-water interface over the structurally high culmination of the pool. The pool was formed by closure created by a growth-type structural high, and by buildup of porous strata over the paleotopographic high produced by this structure during an early stage of development. The underlying Leduc reef contributed to the relief of the paleotopographic high. Carbonate sand banks accumulated on the high, accompanied by a fauna rich in snails and corals. Through dolomitization and solution, both fine pores (intergranular and intercrystalline) and larger pores (moldic vugs) developed. Continued structural uplift and warping produced open breccia fractures and may have been responsible for the accumulation of oil. A typical structural-stratigraphic cross section illustrating the lithostratigraphic units, reservoir units and original oil-water interface is shown in Figure 3. The structural configuration is attributed to uplift, as well as to differential compaction.

Discussion of The 1984 Natl. Petroleum Council Studies on EOR

La discussion porte sur les calculs de permeabilite des roches magasins. Les valeurs de permeabilite utilisees dans la base de donnees DOE/NPC (Department of Energy/National Petroleum Council) pour les reservoirs en gres, sont nettement plus elevees que celles calculees par ELKINS au cours de l'evaluation des projets de recuperation assistee par injection de produits chimiques. L'auteur discute les sources d'erreurs possibles des calculs et les methodes de traitement des donnees provenant des mesures sur carotte. Il propose d'autres methodes pour estimer le volume de l'huile residuelle dans les roches magasins