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Proposal Advanced well architectures are widely considered for accelerating production. This work continues previous work on accelerating recovery via waterflood in application of what has been called p-mode production, in which the objective is to produce up to 50% of the oil in place in the drainage volume in less than 5 years. Previous studies considered only a homogeneous drainage volume. In this study, to evaluate the areal effect of heterogeneity in 2-D, many permeability fields corresponding to different standard deviation (or Dykstra- Parsons coefficient), and various horizontal maximum and minimum correlation lengths (or reservoir connectivity) were generated using geostatistical simulation techniques. Stochastic representation of the reservoir model offers the chance to observe reservoir performance under many equiprobable geological images or realizations. The effect of reservoir heterogeneity on the breakthrough oil recovery and on the pressure drop between the injection and production wells at 50% recovery has been investigated. The simulated cases exhibit a relationship between the breakthrough oil recovery and the watercut at 50% recovery. Three permeability distributions are considered and the geometric mean value in all cases is kept constant. Fifteen sets of realizations were generated for five horizontal maximum correlation lengths and corresponding horizontal minimum correlation lengths. The realizations were then ranked by arithmetic mean permeability. High, medium, and low mean permeabilities were selected for fluid flow simulations that were then used to characterize effects on breakthrough oil recovery and pressure drop at 50% recovery. Results indicated that the maximum correlation length (chosen as perpendicular to flow) aids oil recovery at longer correlation lengths, and that increasing the minimum correlation length (chosen as parallel to flow) increasingly resembles channeling and reduces oil recovery. Greater permeability standard deviation caused larger pressure drop Results showed discernable trends that can be used to orient wells and adjust length and spacing based on expected value ranges for the heterogeneity parameters. The heterogeneity parameters may be estimated in a given situation from actual seismic and log data as well as from expected value ranges associated with a particular analog geology. As such, the analysis presented in this paper can be used to design the well length and spacing in new developments based on data gathered from the appraisal process. Introduction The concept of p-mode production was described in the work by Guerithault, et al. The objective is to produce up to 50% of the oil in place in the drainage volume in less than 5 years. Instead of the waterflooding practice common in the Western hemisphere that commences only after primary production declines and targets a constant water injection rate or injection pressure, p-mode production targets a constant oil production rate that is ensured by injecting voidage-replacement water volumes from the beginning. In this work, the waterflood is conducted with two parallel horizontal wells, one an injector and one a producer. Because the reservoir pressure is maintained at the original value, a p-mode production well couplet does not disturb the surrounding reservoir or wells. Refs. 1 and 2 provided a step-wise first order well construction design procedure that is summarized in the Appendix. The Guerithault work assumed a homogeneous anisotropic (kV kH) formation. A more recent study by Serpen, used the same configuration as Guerithault, et al., and introduced heterogeneity. Reference 4 describes variations in breakthrough oil recovery and pressure drop between the wells as a function of the heterogeneity parameters in the model. This work is summarized in the section below on the heterogeneous model. The subject of this work is to apply what was reported in Ref. 4 to the design concept for a homogeneous formation so that heterogeneity can be taken into account in the design.
- North America > United States (0.46)
- North America > Mexico (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.55)
Horizontal and Deviated Wells Water Disposal Injection Experiences in a Venezuelan Heavy Oil Reservoir in the Orinoco Belt and Future Injection Practices
Briceno, M.C. (SINCOR) | Peralta, J.A. (SINCOR) | Silva, R.J. (SINCOR) | Rismyhr, O. (SINCOR) | Zerpa, L.B. (SINCOR) | Ehlig-Economides, C.A. (Schlumberger)
Abstract Data acquired from permanent pressure gauges over 2 years in a water disposal wells in the Zuata Field, Orinoco Heavy Oil Belt, has revealed significant injectivity declines. Pressure transient analysis over the entire period on a flow period by flow period basis is complicated by severe fluctuations in the injection rate during injection flow periods and rarely analyzable falloff periods. Injectivity is inhibited by large skin at all times. A very strong correlation between injectivity index and skin was determined from pressure transient analysis, which also provides a very high value for the rock permeability thereby quantifying the very high theoretical injectivity expected in the wells. Several hypotheses are considered in order to explain the steep decline in injectivity decline. One of the hypotheses was sanding because it occurred in one injection well when it was shut in quickly and/or under severe fluctuations in rate. Another hypothesis is formation plugging. One possible cause for formation plugging may be a salinity contrast between the injection water and the original formation water, which could activate clay swelling. A second possible cause is formation damage caused by solids and/or organic contaminants in the injection water. In addition to investigations to evaluate the various hypotheses to explain the injectivity decline, a decision was taken to try horizontal injection wells, also equipped with permanent pressure gauges, and in addition, distributed temperature surveillance via fiber optic installed along the entire drilled length of the well. The data from the various wells equipped with permanent pressure gauges and distributed temperature surveillance was augmented by core analysis and laboratory studies of the injection water. The analysis has indicated which the main causes of the injectivity decline are, and measures are being taken to correct the problem. Introduction The Zuata field operated by SINCOR, a consortium consisting of TOTAL, PDVSA and STATOIL is one of the four heavy oil associations in the Orinoco Belt of Venezuela. The location of the field is shown Fig. 1. The reservoir fluid is heavy oil ranging in gravity from 7.5โ9 ยฐAPI with viscosity between 1800 cp and 3500 cp at reservoir conditions. The oil is produced by primary depletion with horizontal wells with at average well length of 4500 ft. The reservoir fluid is mixed with a diluent in the wellbore or at the wellhead before the diluted crude oil is sent to a processing center for water and gas removal. The stabilized oil is taken by pipeline to an Upgrader for further processing. The produced water is injected into the Lower Oficina aquifer. Geological Background The Oficina formation, Middle Miocene, is one of the more prolific intervals in the Eastern Venezuela Basin. In the area assigned to SINCOR, the Oficina formation is subdivided in two main intervals. Lower Oficina, is mainly stacked unconsolidated sands deposited in a braided - meandering fluvial system. Upper Oficina corresponds to sands encased into a shaly sequence associated to a fluvio-deltaic system with tidal influence. Disposal water is injected in the bottom part of Lower Oficina; selected perforated intervals or slotted liner has been located in excess of hundred feet below the Oil Water Contact.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral > Silicate (1.00)
- Geology > Geological Subdiscipline (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.62)
- South America > Venezuela > Orinoco Oil Belt > Eastern Venezuela Basin > Zuata Field (0.99)
- South America > Venezuela > North Atlantic Ocean > Eastern Venezuela Basin (0.99)
- South America > Venezuela > Eastern Venezuela Basin > Oficina Formation (0.99)
Recipe for Success in Ultradeep Water
Ehlig-Economides, C.A. (Schlumberger) | Economides, M.J. (University of Houston)
Abstract Generally, for sandstone reservoirs, shallow deposits tend to be unconsolidated containing heavy oil, and deep deposits tend to be hard rock of low permeability containing gas. The result is an overall leveling of mobility, which relates directly to well potential. Carbonate reservoirs offer significant departures from sandstone trends, and this explains why 8 of the 10 largest and most prolific reservoirs are carbonate formations. Typical trends are altered when a significant portion of the depth to the formation is water depth. More or less, the formation age to depth correlation follows depth below mud line rather than below the water surface. However, the fluids may have experienced pressures and temperatures that would accelerate the maturation process from heavy oil to light oil and, even, gas. The result would be much lower than typical fluid viscosity in very large- permeability sediments, leading to high mobility and extraordinary well productivity. The paper makes the case that under ultra deep waters, in sedimentary environments such as the Gulf of Mexico, offshore Brazil and West Africa, reservoir quality and productivity can be readily inferred and even more to the point, the depth at which specific grade of hydrocarbons can be found. In particular, very large natural gas reservoirs are likely to lie beneath oil reservoirs, the latter containing also large volumes of gas in solution. Information from some of the largest ultra-deep-water accumulations of hydrocarbons shows correlation of depth versus mobility, which is contrasted with data from terrestrial reservoirs. This phenomenon is explained through basic principles. Introduction Deep to ultra-deep offshore petroleum resources are rapidly becoming the next major target for international petroleum exploration and production. Their potential appears already to be very large with reserves estimates for the world already in the hundreds of billions of barrels. Estimates for the United States Gualf of Mexico by a number of analysts already top 50 billion barrels of recoverable reserves. The potential production rates from these reservoirs are also very large, easily surpassing any previous estimates and, even more to the point, they have the potential to compete with the Middle East as the most prolific future source of hydrocarbons. For the United States, work done at the University of Houston over the past two years suggests that offshore petroleum resources in just the Gulf of Mexico, provide the tantalizing possibility in the near future of not only surpassing the maximum modern production of about 3.2 billion barrels per year, accomplished in 1985 thanks to Alaskan production, but also to surpass the maximum annual production rate of about 3.6 billion barrels of oil per year, observed in the early 1970's. (Current US production is about 2.2 billion barrels per year.) Are these forecasts the result of a "grass is greener on the other side" syndrome, the mere fact that technology was incapable to exploit these resources until recently (and even now it is extraordinarily expensive) or, are they the result of specifically applicable laws of physics, which would render these resources compelling? This study investigates the latter and begins by providing reasons why these resources may be expected to be increasingly attractive as access costs diminish. Then, actual data from several thousand offshore reservoirs were examined. and compared with several thousand onshore petroleum-producing formations.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.74)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.94)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
Abstract Severe water coning occurs when producing oil and gas from a strong bottom water drive reservoir. This paper compares and evaluates several new drilling and well completion concepts designed to optimize production and delay water coning. For basic types of vertical well completion (partial, total, reverse and dual penetration) strategies are first examined using reservoir data from a field being developed. Although high water rate production cannot be avoided in all cases, oil rate and cumulative recovery can be significantly improved using total and dual penetration methods. Gel treatment to build a coning barrier was found to be ineffective and uneconomical. Under the same reservoir conditions, alternative options such as fracturing, horizontal well and short radius laterals were also evaluated. Multiple laterals that can be implemented with current drilling technology offer a promising strategy for delaying water cresting and enhancing production. Introduction For understanding well production performance in a reservoir under strong bottom water drive, nothing is more revealing than observing the near-well fluid flow geometry and pressure distribution under different well drilling and completion schemes. Some of the fluid flow constraints and restrictions are inherited. Some are artificially created by the well drilling and completion scheme. This entails selection of well location, well spacing, type and extent of completion and perforation. These inherited and imposed constraints effect the pressure drawdown distribution near the well. In turn, a near-well fluid flow geometry develops progressively. For vertical wells open to flow only in a portion of the oil zone and for horizontal wells drilled above the oil-water contact, water from the underlying aquifer moves upward to a characteristic shape. For these strategies, the key to successful reservoir exploitation is to maximize the volume swept by the rising water by manipulating the flow geometry. By virtue of the shape of the swept volume under the rising water, breakthrough at the perforation interval is called coning in vertical wells and cresting in horizontal wells. This adverse water entry at the wellbore impedes oil and gas production. It bypasses the hydrocarbon reserve, modifies the oil and gas contact with the wellbore, and increases the wellbore hydrostatic pressure which reduces the bottom-hole flowing pressure and hence, the drawdown pressure. In addition it can generate formation damage such as wettability change, water block (high water saturation), emulsion and scale deposition. The maximum water-free oil production rate is called the critical rate. A great number of authors have conducted experimental, analytical and numerical studies on coning behavior in vertical wells. Based on empirical or analytical equations, these studies neglected some key factors such as varying bottom water influx rate and pressure, and viscous/gravity and capillary pressure effects, and they predict generally low and uneconomical critical coning rates and critical drawdown pressure. The controlling parameters are either geometrical, namely the effective wellbore and drainage radii, the location and length of perforation interval, and the distance of deepest perforation to water/oil contact (WOC) or physical, namely the hydrocarbon/water density contrast and the ratio of horizontal to vertical permeability. P. 409
Hydraulic Fracture Stimulation of Highly Permeable Formations: The Effect of Critical Fracture Parameters on Oilwell Production and Pressure
Mathur, A.K. (Schlumberger Dowell) | Ning, X. (Schlumberger Dowell) | Marcinew, R.B. (Schlumberger Dowell) | Ehlig-Economides, C.A. (Schlumberger Oilfield Services) | Economides, M.J. (Texas A&M U.)
Abstract Hydraulic fracturing of moderate to high-permeability reservoirs with short, highly conductive fractures is a technique often applied to improve well productivity through penetration beyond near wellbore damage. This paper investigates the effect of important fracture parameters (e.g., fracture half-length, fracture conductivity, and fracture-face damage) on the short-term behavior and long-term productivity of the well. The degree and extent of near wellbore damage, in addition to the fracture parameters, are varied in the sensitivity analysis. A case study from the Gulf Coast addresses the effect of these important parameters on the well response. It is evident the length and conductivity of a created hydraulic fracture have an important effect on the poststimulation performance of a well. Some of these fractures may be damaged. Damage to the proppant-pack has considerable effects, reducing the fracture conductivity. Generally fracture-face damage caused by fluid and polymer leakoff does not significantly alter long-term production, assuming the permanent reduction of absolute permeability is low (less than 90%) and provided the fracture bypasses the radial damage zone in the formation. When the fracture face damage is high (greater than 90%), early time well response is significantly impaired by the fracturing fluid cleanup process. This has implications on the timing of poststimulation pressure transient analyses. The modeled behavior and recommendations for the design of such tests are presented. Introduction A two-step-in-one fracture stimulation and gravel-pack procedure, has been emerging as a preferred well completion technique in soft formations and higher permeability reservoirs. Employing a technique known as tip screenout (TSO), the lateral fracture propagation is arrested, the fracture is inflated, and the resultant fracture is short and, presumably, highly conductive. A large fracture conductivity is required in higher permeability reservoirs while the fracture half-length is of secondary importance. Until recently, these treatments have encroached into extraordinary permeability ranges. Reservoirs with permeabilities of 2000 md or greater have been targeted. The execution of these treatments is burdened by considerable leakoff which is especially severe in higher permeability reservoirs. Filter-cake-building fracturing fluids (such as crosslinked polymer solutions) are employed to prevent the invasion, of polymers into the reservoir, normal to the direction of fracture propagation. These fluids effectively limit an invasion for reservoir permeabilities up to 50 md. For higher permeability reservoirs, crosslinked polymer solutions may invade the formation. Linear gels have been employed in a misguided attempt to reduce "fracture damage." The latter has been frequently confused. There are two distinct types of damage:proppant-pack damage inside the fracture, resulting from unbroken polymer chains, with a major impact on the created fracture conductivity, and fracture-face damage which refers to permeability impairment outside the fracture and normal to its. P. 237
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Western Canada Sedimentary Basin > Greater Peace River High Basin > Valhalla Field > Kaskapau Formation > Aec Erl Valhalla 4-5-74-8 Well (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Greater Peace River High Basin > Valhalla Field > Kaskapau Formation > Aec Erl Valhalla 4-5-74-8 Well (0.99)
Abstract Fluid flow rate and density at the sandface measured during drawdown in a drillstem test (DST) are key measurements that are normally unavailable using conventional techniques. Production logging flowmeters cannot be used in most cases, and the presence of wireline in the test string when the well is flowing is sometimes an undesirable complication. Furthermore, intrusive devices such as spinners have proven especially vulnerable to damage by cuttings and produced sand. This paper presents field data recorded using a prototype downhole multiphase flowmeter sensor that is particularly well-adapted to DST. This fullbore tool can be positioned below the test valve and provides continuous mass flow rate, density, pressure and temperature measurements. Drawdown data were interpreted to yield permeability, skin and reservoir limits which were comparable to the values determined from a conventional buildup interpretation. In addition, it was possible to monitor any changes in skin while flowing the well during the cleanup period. Introduction A DST (Fig. 1) is a well test performed using a temporary completion run on drillpipe or tubing. Two classic DST environments considered in this paper are (1) openhole, low flow rate wells that do not produce to the surface, typical for example of land operations in the US, and (2) cased hole, high flow rate wells that do flow to the surface, as is normally the case offshore. DSTs may be run in conjunction with completion operations such as tubing-conveyed perforating (TCP) and stimulation. Conventional DSTs measure downhole pressure during a series of flow (drawdown) and shut-in (buildup) periods. The first drawdown is typically brief and intended to displace mud and drilling debris from the vicinity of the sandface (cleanup). The data acquired during the second drawdown-buildup sequence are considered more representative of the virgin reservoir and, hence, are generally used for interpretation purposes. Given sandface pressure and flow rate data, both drawdown and buildup can be interpreted to yield estimates of important reservoir parameters such as permeability and skin. However, flow rate is much more difficult to measure than absolute pressure, particularly when more than one phase is present. The tendency therefore is to neglect the drawdown for want of an adequate flow rate measurement, and concentrate interpretation efforts on the buildup when the flow rate is zero and hence "known." There are, however, several disadvantages to this approach. Since the changes in reservoir pressure due to any change of rate continue to have an effect due to superposition on subsequent flow and shut-in periods, the flow period or periods that precede the buildup of interest must be accounted for in the flow history. The interpretation, therefore, requires knowledge of the flow history, which, in the absence of a flowmeter, has to be estimated either from extrapolation of surface flow rate readings (if any) to downhole conditions or from knowledge of the pipe fillup. Either technique is, at best an average that fails to account for short-time variations at the sandface and can lead to ambiguities in model diagnosis. Furthermore, to avoid excessive superposition effects in the late-time buildup data, the main flow and the buildup should be of similar length. When an objective of the test is the evaluation of reservoir limits, the total test time is, thus, more than twice the duration of the buildup. Finally, because the buildup pressure has a lower signal-to-noise ratio and is more sensitive to gauge drift than while flowing, drawdown transient data has a potential to provide superior interpretation results. P. 575^
Abstract Data acquisition techniques for computer-based systems are discussed for making continuous pressure, temperature and flow measurements. To ensure that the data faithfully represent the essential signal content over the time interval of interest, the important considerations for each system are measurement resolution, signal bandwidth, sampling, filtering and aliasing. Key data transmission techniques are discussed, starting with downhole recorders that must be hauled out of the hole for data retrieval, to telemetry systems for sending real-time or bulk data transmissions to the surface. The important issues for downhole recorders are storage media and capacity. For signal transmission systems, the issues are information modulation, data and error rate, and signal-to-noise ratio. Introduction This paper is an overview of the computer-based data acquisition and transmission techniques used in making pressure, temperature and flow measurements during well testing. Although there are many different types of commercially available systems from many different companies, the specifications and terminology tend to be aimed at specialists in electronics rather than reservoir engineers. Therefore, to make this a worthwhile overview to the SPE community, we focus on the key fundamentals that are common to all these systems and show field examples to help the reservoir engineer understand and apply this knowledge appropriately. Figure 1 shows the block diagram of a generalized data acquisition and transmission system. This, system must provide the computer with data that is a faithful representation of the measurements made downhole. In a well test, the sensors measure the desired parameter (e.g., pressure, temperature, flow rate, etc.) and convert the measured parameters into voltage, current or frequency signals. The acquisition block works exactly as its name implies: in it the measurement signals are acquired and converted into a form suitable for transmission to the surface or storage in a downhole recorder's memory. In the transmission block the acquired signals are encoded or modulated onto a transmission medium and delivered as computer input. Data Acquisition In a computer-based data acquisition system the analog signal from the sensor is converted into a digital signal by a process of sampling and analog-to-digital (A/D) conversion. There are several important considerations for this conversion, such as full-scale range, resolution and sampling rate. To illustrate these we first compare the decimal and digital representation of the same number. We are accustomed to using the decimal system where a whole number, p, is represented by its decimal coefficients. For example, the decimal number 253 really represents (1) In a digital system, 253 becomes the binary number: 11111101, where (2) Digital Resolution A digital system's resolution is determined by the number of binary bits, n, for each measurement and the system's full-scale range (F.S.): (3) P. 695^
- Information Technology > Communications > Networks (0.54)
- Information Technology > Data Science (0.46)
Abstract Diagnosing the reservoir model from a field data set is one of the main challenges in well test analysis. The log-log pressure and pressure derivative plot is now firmly established as a primary diagnostic tool. This paper provides a new derivative formulation that enhances model provides a new derivative formulation that enhances model diagnosis and addresses techniques for reducing noise in the derivative response. Transients initiated by a sufficiently large increase in the surface rate closely represent the ideal reservoir response. However, when a transient is initiated by a decrease in surface rate, distortions due to superposition effects from previous surface flow rate changes are frequently present previous surface flow rate changes are frequently present in the late-time derivative and can lead to incorrect characterization of reservoir boundaries. To improve the late-time response, the pressure data are corrected for effects of a variable surface rate history before differentiation. The resultant desuperposition derivative avoids assuming a model for the reservoir behavior by using the late-time character of a representative transient. The desuperposition derivative appears as an equivalent drawdown (injection) response regardless of the nature of the perturbation that was actually used to induce the particular transient. This technique is particularly useful in reservoir and limits tests designed to particularly useful in reservoir and limits tests designed to delineate heterogeneities or boundaries; it also applies to multirate and multilayer tests. Noise in the derivative can either mask or give a false impression of the true reservoir behavior. Overly smoothing noisy data may obscure the response and lead to erroneous model diagnosis. This study addresses logarithmic filtering and sampling techniques for reducing noise in the data. Introduction From its inception, the log-log pressure derivative plot has played a fundamental role in reservoir model diagnosis. For tests where downhole flow rates are acquired, its counterpart is the convolution derivative. Experience with these diagnostic plots has shown that the shape of the classical derivative response depends on the overall well test sequence. These discrepancies typically occur in late time and can interfere with the correct characterization of boundary effects. Model diagnosis entails pattern recognition, during which the shape of the derivative of the transient test data is identified with a known reservoir model. The comparison may be achieved visually or automatically by applying artificial intelligence techniques. Since the late-time derivative shape can be influenced by the test sequence and the well flow rate history and may not necessarily match a shape in the lookup catalogue of theoretical drawdown responses, misdiagnosis of the reservoir model is a possibility. Misdiagnosis will likely be corrected during subsequent analytical modelling because the data are matched with a simulated reservoir model response that accounts for the entire rate history. However, a match might be obtained using an improper model resulting in incorrect reservoir characterization. Pressure and convolution derivatives are currently Pressure and convolution derivatives are currently computed by differentiating with respect to radial superposition and convolution time groups, respectively. This paper describes a desuperposition technique which paper describes a desuperposition technique which renders the derivative as an equivalent drawdown or injection response which can be directly compared with theoretical type curves. The desuperposition technique is explained for pressure, convolution, and deconvolution derivatives, and a simulated example shows its application. P. 201