In this paper, we investigate whether foams can show placement properties that are superior to those of gels, when used as blocking agents. Specifically, we examine whether the concept of limiting capillary pressure can be exploited to form a persistent, low-mobility foam in high-permeability zones while preventing foam production and formation damage in low-permeability zones. Using a C14-16 a-olefinsulfonate, we measured mobilities of a nitrogen foam in cores with permeabilities from 7.5 to 900 md (750 psig back pressure, 104°F), with foam qualities ranging from 50% to 95%, and with Darcy velocities ranging from 0.5 to 100 ft/d. We also extensively studied the residual resistance factors provided during brine injection after foamplacement. The results from our experimental studies were used during numerical analyses to establish whether foams can exhibit placement properties that are superior to those of gelants. This study found that compared with water-like gelants, the foam showed better placement properties when the permeabilities were 7.5 md or less in the low-permeability zones and 80 md or more in the high-permeability zones.
Gels have often been used to reduce fluid channeling in reservoirs.1 Several other types of materials (including foams) have also been considered for this purpose.2 When using blocking agents to reduce channeling, a critical question is, How can the blocking agent be placed in high-permeability zones without damaging less-permeable, hydrocarbon-productive zones? Mere, we investigate whether foams can show placement properties that are superior to those of gels, when used as blocking agents. Specifically, we examine whether the "limiting-capillary-pressure" concept3 can be exploited to form a persistent, low-mobility foam in high-permeability zones while preventing foam production and formation damage in low-permeability zones.
In this paper, we first explain the concept of limiting capillary pressure. Second, we summarize our experiments where foam mobilities were determined over a wide range of conditions. Using a C14-16 a-olefin sulfonate, we measured mobilities of a nitrogen foam in cores with permeabilities from 7.5 to 900 md (750 psig back pressure, 104°F), with foam qualities (gas volume fractions) ranging from 50% to 95%, and with Darcy velocities ranging from 0.5 to 100 ft/d. We also extensively studied the residual resistance factors provided during brine injection after foam placement. Finally, the results from our experimental studies were used during numerical analyses to establish whether foams can exhibit placement properties that are superior to those of gelants.
In conjunction with the DOE Project (DE-FC22-93BC14990), the characterization of a portion of the Pernmian age San Andres formation under Welch Field, Dawson County, Texas was initiated. The objective of the characterization is the construction of a geologic model for the numerical simulation of a CO2 flood of the reservoir. A detailed reservoir description is required because the high costs to inject and recycle CO2 dictates a very efficient flood design. Identification of reservoir barriers, flow units, and prediction of continuity present the greatest challenge to the description. The productive portion of the formation is mineralogically simple, consisting of dolomite and anhydrite with very minor amounts of chert and illitic clay. Deposition occurred in a very flat shallow shelf setting ranging from supra tidal to subtidal. Depositional textures are variable ranging from fenestral mudstones to oolitic grainstones, with wackestones and packstones dominating. Diagenesis of these shallow shelf deposits has created a highly complex pore system which at times crosses depositional facies boundaries. Rock fluid interaction further complicated the descriptive process by affecting the log responses.
Porosity-permeability cross plots exhibited good correlation for a carbonate reservoir but were too coarse for simulation purposes. Special core analysis tests of capillary pressure and relative permeability provided the key for identifying the intervals of differing wettability and pore structure. A methodology has been developed to identity the varying pore, systems and differing wettabilities, using multiple logs from a routine logging suite and special core analysis. The input from multiple log measurements provides a better estimation of the formation absolute permeability than by using a single porosity-permeability relation. These reservoir parameters could then be extrapolated to uncored wells, using the sequence stratigraphy framework, to build the 3-D model of the reservoir.
West Welch Unit, located in the northwest corner of Dawson County, Texas.(Fig. 1) produes 32 API gravity oil, by solution gas drive, from the Upper San Andres formation at an average depth of 4800 to 4900 feet. The field was discovered in 1936 and unitized in 1960. Water flood operations began in 1960-1962.
The reservoir is a combination trap with an updip loss of reservoir quality on a monoclinal structure to the northwest, with down dip water and reservoir degradation in lateral positions. The Main Pay interval consists of two parasequences prograding toward the basin. Porosity is lost as the supra tidal deposits dominate the system. The better reservoir quality exists in the subtidal rocks. The formation in the producing section is completely dolomitized with significant quantities of anhydrite. The anhydrite occurs as isolated nodules, coalesced beds, pore filling, and matrix replacement. The diagenesis has altered the original depositional fabrics to create a complex pore system. Pore types include interparticle, intercrystalline, intraparticle, and moldic (vugular). Although lateral continuity of beds extends for miles, reservoir quality varies radically. Dykstra Parsons coefficients range from 0.77 to 0.89 for the project area. Average porosity is 12 percent and geometric mean permeability is 1 md.
The results presented herein were derived from a partially funded DOE Class II project (DE-FC22-93BC14990). The scope of the project required the geologic description of the reservoir for numerical simulation to design and implement an economic CO2 flood in a low permeability, heterogeneous reservoir. One of the objectives is to develop methodologies by which other operators can perform the descriptions in other fields.
AbstractCO2-foam has been long realized as an effective mobility reducing agent for CO2 flooding in oil recovery process. Recent researches indicate that some CO2- foams also show an exciting additional characteristic, selective mobility reduction (SMR), in which the mobility of foam is reduced by a greater fraction in high than in low permeability cores in laboratory experiments. Examples of such an unusual property are presented first in this paper to show the mobility dependence of CO2-foams on the rock permeabilities ranging from 30 to 900 md. Secondly, a simple modeling procedure is introduced to evaluate the benefits of using an SMR displacing agent in a typical oil recovery process. In this model, the mobility of the displacing fluid is considered to be proportional to the permeabilities raised to a specific exponent. This allows us, for different values of exponent from zero to one, to examine how different degrees of SMR will affect the oil recovery. The modeling results show that, as expected, the breakthrough time of the faster (higher permeability) layer is delayed and the vertical sweep efficiency of the model is improved if the mobility of the injected fluid is reduced. Furthermore, this improvement becomes even more significant when an SMR fluid is used for the displacement. Even a slightly favorable SMR fluid, that shows a slight dependence of mobility on rock permeability, can significantly reduce the number of pore volumes required to achieve the same degree of recovery as that realized with an ordinary mobility reducing agent.
A two-phase, two-dimensional, dual-porosity, dual-permeability simulator is developed to study the effects of multimechanistic flow of gas and water through tight, fractured reservoirs. The formulation incorporates the Newton-Raphson procedure to linearize the set of highly non-linear partial differential equations. These equations are then solved in a fully implicit form to obtain pressure and saturation distributions within the fracture network and the matrix.
In this paper, we discuss the development of the multimechanistic flow simulator with respect to fractured systems. For the multimechanistic systems, higher flowrates and cumulative production are seen at early times. This is attributed to the higher drawdowns experienced by such systems. At late times, a "choking effect" is hypothesized to be responsible for higher cumulative production from systems experiencing multimechanistic flow.
The primary motivation of this study is to further the understanding of multiphase fluid transport characteristics through tight, naturally fractured porous media such as the Spraberry Trend in western Texas and the carbonate Bombay High offshore field in India. The italicized terms implicitly assign certain properties to the system, the study of which formed the focus of this work. These terms are briefly defined in the following paragraphs as they are used in this study.
Tight: implies low absolute permeability. It also implies that the process of diffusion maybe responsible for a significant fraction of fluid transport.
Fractured: implies a heterogeneous system comprising both matrix and fractures. The fractures are assumed to be interconnected and are solely responsible for conducting the fluids to the wellbore. The matrix forms localized source/sink terms in the system due to its large storativity. Since fractured systems clearly imply two major domains of fluid storage and transport, the physics of fractured systems cannot be adequately modeled using conventional single-porosity models. In this context, a tight, naturally fractured system implies low matrix permeability.
Conventionally, most fractured systems have been modeled using the dual-porosity, single-permeability (DPSP) concept. This concept implies that the matrix blocks do not communicate with each other, and as mentioned above, just act as passive localized sources/sinks with respect to the fracture network. This study was motivated by the hypothesis that a tight, fractured system could experience the multimechanistic flow phenomenon whereby the fluid flow is caused by pressure and concentration gradients. In other words, the total velocity of a phase is comprised of Darcian and Fickian components. These velocity components are assumed to act parallel to each other and thus are vectorially additive (Ertekin et al., 1986). To model the multimechanistic flow concept rigorously, we also assume that the matrix blocks are in causal contact with each other. This assumption suggests that the matrix blocks form active sources/sinks as well as relatively significant flow conduits for the fluids. This demarcates the dual-porosity, dual-permeability (DPDP) concept from the dual-porosity, single-permeability concept. Hence, to understand the physics implied by the multimechanistic flow, one needs to model tight, fractured systems using the dual-porosity, dual-permeability concept which allows flow between matrix blocks.
This paper presents a review of the benefits and performance of downhole percussion hammers. The advancement of drilling technology and the extensive use of coiled tubing coupled with different downhole motors prompted another look at the percussion type of drills. Achieving very high extended reach wells also have nessitated a high axial driving mechanism. The potential benefits of the percussion type of drilling machine for future operations are given, supported by the performance of the tools. The use envelope and the benchmarks of the tools by different manufacturers down the years have been discussed. The hammers developed and operated have been supported by enough field runs to prove the sustainment of the tools. Different models of downhole hammers can be categorized as first generation tools which include the developments from early time to the development of Bassinger tools. The second generation tools from post-Bassinger to the recent developments are discussed broadly. The basic principle involved and the necessity to consider the correct stress waveform to simulate the performance of the downbole hammer energy transfer are reviewed.
Millennia of time have transpired since the surface of the earth was first penetrated by human beings for their needs that could not be obtained on the suface of the earth. There are several milestones in the progress of cutting machines. Cable tool was an early form of making a hole by cutting rocks by impact through dropping a heavy hammer attached to a cable. The disadvantages of cable tool drilling were limited number of blows, slow rate of penetration (ROP) and weak cable link. Slowly, cable tool drilling was replaced by the rotary type of drilling methods. This resulted in continuous rock-bit interaction. Weight on the bit (WOB) was increased by increasing the number of drill collars above the bit. Continuous hole cleaning, using mud or air/gas as the circulating medium, contributed to better hole conditions as well as bit cooling and lubrication. The worldwide acceptance of the rotary method and tools made the introduction of new technology in drilling methods difficult. Recent increases in application of horizontal wells and in particular slim lateral holes, resulted in the development of coiled tubing drilling. Since, in coiled tubing drilling system the coiled tubing cannot be rotated, a downhole motor is essentially required for drilling. Despite the accelerating pace of improvements in downhole motors, efficient slimhole motors remain unavailable.
Increasing cost per foot, using the conventional drilling methods and the flattening of the efficiency achieved by rotary drilling, have necessitated a re-look at other modes of cutting the rocks. This led to the idea of the percussive type of drilling. The word "percussion" means impact or collision or vibratory shock which is one of the most powerful forces. The principle of utilizing the energy generated by the impact load to cut the rocks, caught the eyes of the researchers early in the 1950s. The principle came down in the form of percussion drills and was called by several names, such as downhole hammer, percussion hammer, percussive drill, down-the-hole hammer, etc.
A novel material balance technique presented by Kumar et al1 has been applied to estimate areal pattern distribution of remaining oil saturations, ROS, in a mature West Texas San Andres carbonate waterflood which is a potential candidate for the implementation of an improved oil recovery (IOR) project. This material balance accounts for two major dynamic unknowns: (1) loss of injected water vertically into non-target zones, and areally to adjacent patterns, and (2) progressive gas fill-up that begins with the start of water injection and may continue for several years before reaching the maximum fillup.
The calculation procedure discussed here can be easily converted to a spreadsheet program and requires only readily available field production and injection data for oil, water and gas. The results indicate that 50 of the 103 patterns in the unit have been depleted to waterflood residual oil saturation, Sorw, and 33 patterns comprising 42% of the pore volume have relatively high ROS (>45%) even after 18 years of injection. A normal distribution in ROS is obtained in this unit with ROS ranging from a high of 67% to a low of 21%. This information is highly desirable for waterflood surveillance, monitoring, and in planning for an IOR project.
As the U.S. reserve base continues to mature, the technical requirements for economical depletion of these reserves are changing dramatically. A large number of small and/or marginal waterflood properties are changing hands, moving from major oil companies to independents, and from large operators to small operators. Limited revenue streams from these small and aging waterfloods direct attention to finding cost effective ways to analyze reservoirs with limited and commonly available field information such as production and injection well data. Such properties cannot support the expense or manpower requirements associated with extensive data gathering for a reservoir simulation study.
Many small and mature waterflood properties are also being screened for possible applications of an IOR project, or for flood modifications in preparation for an IOR project. A key piece of information to assure economic viability is the remaining oil saturation (ROS) within a property and identifying the areas with the highest ROS. While special core analysis (SCAL), log-inject-log, and thermal-decay-time (TDT) log evaluation techniques are available, they provide only single point values and a snapshot in time near a wellbore. A representative set of wells have to be selected for obtaining an areal distribution characterization within a field. This can quickly run into an expensive program. Davies et al2 provide an example of a North Sea sandstone reservoir where wide areal variation in ROS is observed.
Production data represent a source of information about the ongoing dynamic flow process in the reservoir. A proper analysis of these data might therefore give an indication of the relationships governing the fluid flow. Exploratory data analysis is one tool which can be used to extract the required information and to establish a statistical significance to the results. This paper presents a simple approach to examine the interwell communication and interference of a mature waterflood in order to identify and rank areas of potential improvement. Using this as a screening process we can identify areas with the best potential for further and more detailed studies. In addition some of the problems and limitations associated with analysis of production data are discussed.
Is there an easy way of evaluating waterflood performance based solely on surface measurements in the form of rates and pressures? Although production data have always been a key part of any waterflood evaluation, no good answer has been given to what we can expect to get from such an analysis.
Exploratory data analysis of production data is aimed at organizing and representing the data in an easy interpretive way. The analysis can take place at two levels, global and local. The global level will examine large scale trends (multiple wells), whereas the local analysis will focus on single well behavior and interwell relationships (well pairs). The use of production data as an analytical tool depends upon the quality and density of the data. More data of higher resolution and quality will yield significantly more information than irregular and poorly measured data. The quality of the analysis is therefore a direct function of the quality and the density of the measurements.
The analysis of production data poses a particular challenge since we have a 3-dimensional data set mixing both the spatial and the temporal (time) dimensions. Stationarity assumptions along the spatial plane do not translate into stationarity along the temporal axis. Special care is therefore necessary when dealing with both the spatial dimensions and the temporal dimension simultaneously. In addition, the surface measured production data constitute a 2-dimensional spatial plane, which represents the dynamic behavior of a 3-dimensional reservoir. Another challenge is the size of the data set which comprises the production data. An efficient handling and representation is therefore important to obtain a clear interpretation.
The primary objective of the methodology presented in this paper is to screen the field data to identify and rank areas of potential production improvement for a mature waterflood, in the form of changes to the individual wells, operational changes to the water injection allocation, infill drilling or pattern reorientation. This identification process depends upon the ability to extract information about the connectivity, sweep and interference among injection and production wells based on production data. Having identified potential areas of improvement, these areas can be further evaluated based on the geological knowledge and a more detailed reservoir study.
SPE 35161 Pressure Transient Data Acquisition and Analysis Using Real Time Electromagnetic Telemetry L.E. Doublet,* Texas A&M U., J.W. Nevans,* Fina Oil & Chemical Company, M.K. Fisher,* ProTechnics Company, R.L. Heine,* Real Time Diagnostics, Inc., and T.A. Blasingame,* Texas A&M U. *SPE Members Copyright 1996, Society of Petroleum Engineers, Inc.
This paper presents the operational procedures and the results for two pressure buildup tests performed using a wireless telemetry acquisition system (TAS) tool at the North Robertson (Clearfork) Unit (NRU) in Gaines, Co. Tx. Using a single pressure gauge system downhole we obtained real-time telemetry of pressure and temperature data at the surface, as well as a larger sampling of data that were stored in the downhole memory system.
This new wireless telemetry acquisition system was developed to provide real-time pressure and temperature data at the surface by using an electromagnetic signal to transmit these data through the formation strata. The tool is fully programmable so that a wide range of sampling frequencies can be used. The system allows pressure and temperature data to be stored downhole (as in the case of a typical "memory" gauge), or these data can be transmitted to surface data acquisition systems. This provides real-time pressure and temperature data for pressure transient tests, stimulation monitoring. and long-term reservoir surveillance.
Our objective is to demonstrate the use of this technology for pressure buildup tests in low permeability reservoirs. Our goal in utilizing this technology is to reduce the shut-in time requirements for pressure transient tests - which will ultimately result in a more cost-effective reservoir surveillance program as wells can be returned to production (or injection) as quickly as possible.
Once the pressure data were acquired, we performed conventional semilog and log-log analysis, and we simulated test profiles to verify the analyses of the test data. Both surface and downhole pressure data were compared for consistency, and both types of data were analyzed in exactly the same fashion. The results of these analyses were essentially identical. This approach gave consistent estimates of reservoir pressure, permeability, skin factor, and fracture half-length for both of our case histories.
The accurate acquisition and analysis of pressure transient data is an integral part of the reservoir surveillance process. By analyzing the characteristic shape of the pressure-time profile we can determine the reservoir-well model (i.e., homogeneous or dual-porosity reservoir conditions, hydraulically-fractured or horizontal well behavior, wellbore storage conditions, etc.).
Specifically, we can use pressure transient data to estimate the following:
-average reservoir pressure,
-completion efficiency, -reservoir quality, -well drainage radius and reservoir shape, and -flow boundaries or other reservoir heterogeneities. Unfortunately, in the majority of operating environments the critical issue for most pressure transient tests is the timely return of a well to production or injection. This paper presents one methodology that shows promise in minimizing test time while fulfilling the data acquisition requirements.
When performing pressure transient tests in the low permeability reservoirs of the Permian Basin (such as the NRU), it has been our experience that a test of at least two to three weeks is required for a comprehensive analysis to be possible. The issue is that the low permeability character of these reservoirs, combined with often severe wellbore storage effects, distorts test data and conventional analysis techniques cannot be used until these effects end. One remedy is a downhole shut-in device. but this device can be difficult to install, it requires considerable well preparation, and is quite expensive. Our approach was to minimize the test time by using real-time data for analysis. Conceptually, we can monitor the test and terminate once a valid analysis is obtained - but in our cases we continued data acquisition until the power source in the tool depleted. We did this for two reasons - first, we wanted to acquire as much data as possible; and second, we wanted to establish the practical operating limits of this data acquisition system. To estimate well drainage radius and identify flow boundaries we have found from pressure falloff tests that a total test duration of between five and eight weeks is required. Obviously, it is not economically feasible to shut-in producing wells for this period of time. In the future we may use the TAS tool for long-term surveillance tests, but at present this task is neither operationally nor economically feasible. P. 149
In the past, slickline service has been considered as an option suited only to routine mechanical well workovers. This is no longer the case. New technology has expanded slickline capabilities to include services for well interventions that have traditionally been reserved for other, more-costly alternatives. This paper will discuss the innovative equipment that has been developed to support this technological expansion, all of which plays an integral part in the expanded slickline concept, specifically:
An electronic triggering device that provides a safe, efficient method for firing detonators
A battery-operated, electro-mechanical tool that is capable of setting wellbore devices with slickline and braided line without explosives.
An electronic measurement system that can automatically correct measurement inaccuracies resulting from line stretch and environmental stress factors.
A collar locator that can provide verification of collar locations in a tubing or casing string.
Data/job loggers or acquisition software systems that can be connected to the electronic measurement system to graphically record dynamic information that occurs during a wireline trip.
A wireline inspection system that can determine integrity of both new and used mechanical wirelines during and before service.
Case histories will be used to provide comparisons of cost, operational efficiency, and enhanced safety features of traditional service options and the new advanced slickline system. Methods for service strategies that support current economic trends and well solutions will also be discussed as well as methods to determine key needs for appropriate service alternatives.
The combined use of these slickline tools provides a state-of-the-art service system that can provide efficient alternatives for the advanced service needs in the oilfield today.
Modern slickline services have grown from their forerunners - flat measuring lines, that were used in the early days of the petroleum industry for measuring well depths. The flat measuring lines were calibrated with marked or stamped figures similar to those on a surveyor's tape. As well depths increased, so did the problems with the traditional tapes. Procuring tapes of sufficient length became difficult, stretching of the calibrated tapes under loads reduced accuracy (so that it was necessary to correct readings to get accurate depths), and when measuring lines had to be run in a well under pressure, the flat tape was difficult to run through packing in a stuffing box. These disadvantages initiated the adoption of the circular wire for measuring depth. The circular wire was tagged at equal increments of length, and the operator kept a record of the amount of line paid out and retrieved. Later, measuring devices with calibrated wheels came into use because they were more convenient and provided greater accuracy in measurement.
The first slickline that came into general use was for following the plug during cementing operations. As well depths increased, and loads imposed on measuring lines increased, it became necessary to develop higher-strength slickline materials to keep the diameter size of the wire as small as possible. Since that time, many improvements have been made in the wire, slickline drives, and measuring devices, and slickline servicing provides an effective means for performing well maintenance by high speed mechanical deployment, manipulation and retrieval of downhole service tools. Its portability allows it to also be cost efficient for performing such services in remote locations and on satellite platforms.
The application of cyclic CO2, often referred to as the CO2 Huff-n-Puff (H-n-P) process, may find its niche in the maturing waterfloods of the Permian Basin. Coupling the CO2 H-n-P process to miscible flooding applications could provide the needed revenue to sufficiently mitigate near-term negative cash flow concerns in these capital intensive projects. Initial results from a field demonstration of the process are provided. The paper briefly reviews the reservoir characterization associated with the project and the compositional simulation of the CO2 H-n-P process. Simulation results suggest that reservoir characterization of flow units is not as critical for a CO2 H-n-P process as for a miscible flood. Entrapment of CO2 by gas hysteresis is considered the dominant recovery factor for a given volume of CO2. The repetitive application of the process was found to be unwarranted in a waterflooded environment. Future history matching of the performance will allow better forecasts and evaluation of the economic impact available with this underutilized process.
The CO2 H-n-P process is a proven enhanced oil recovery technology in Louisiana-Texas Gulf-Coast sandstone reservoirs.1,2 Application seems to mostly confine itself to low-pressure sandstone reservoirs.3 The process has been shown to be moderately effective in conjunction with steam on heavy California crude oils.4,5 A review of earlier literature1,6,7 provides an excellent introduction to the theory, mechanics of the process, and several case histories. Although the technology is proven in light oil sandstones, it continues to be a very underutilized enhanced recovery option for carbonates. However, the theories associated with the CO2 H-n-P process are not lithology dependent.
A significant amount of oil reserves are located in carbonate reservoirs. Specifically, the carbonates deposited in shallow shelf (SSC) environments make up the largest percentage of known reservoirs within the Permian Basin of North America. Many of these known resources have been under waterflooding operations for decades and are at risk of abandonment if crude oil recoveries cannot be economically enhanced.8,9
Miscible CO2 flooding is the process of choice for enhancing recovery of light oils10 and already accounts for nearly 12% of the Permian Basin's daily production.11 There are significant probable reserves associated with future miscible CO2 projects. However, many are marginally economic at current market conditions due to large up-front capital commitments for a peak response which may be several years in the future. The resulting negative cash-flow is sometimes too much for an operator to absorb. The CO2 H-n-P process is being investigated as a near-term option to mitigate the negative cash-flow situation - allowing acceleration of inventoried miscible CO2 projects.