Summary. Removal of wax from wells and flowlines can account for significant additional operating costs. To evaluate these potential costs, the operating conditions that allow waxes to precipitate in the wellbore must be identified, and deposition rates must be estimated to determine the costs associated with removal of wax deposits. Presented in this paper are laboratory and analytic methods that can be used to estimate both the critical operating conditions and the deposition rates. The laboratory tests and analysis presented may be used to characterize any type of oil. Introduction Deposition of wax in production tubing and pipelines reduces operating efficiency. The costs of removing wax deposits can be substantial. The degree of wax deposition in wells, however, cannot always be predicted by previous experience in a particular reservoir. The operating conditions in the well are as important as the oil composition in predicting wax problems. Wax deposition is particularly problematic in low-rate wells. Low flow rates in wells affect wax deposition mainly because of the greater residence time of the oil in the wellbore. The increased flow time permits more heat loss and leads to lower oil temperatures, which in can lead to wax precipitation and deposition. Wellbore studies have shown that the temperature profile in the wellbore is a strong function of the flow rate. The operating pressure in a wellbore also affects wax deposition through its effects on solution gas. As oil flows up the wellbore, its pressure drops, and if the oil is saturated with gas, this pressure drop causes gas to be liberated. Because solution gas acts to some degree as a solvent for waxes, the loss of dissolved gas as the crude flows up the wellbore makes precipitation more likely. Solution gas also affects the rate of wax accumulation through its effects on oil viscosity.A program of laboratory experiments was undertaken to resolve differences between previous predictions and field experience and to quantify the effects of varying the oil flow rate. Three types of experiments were undertaken:wax crystallization experiments on live oil to define the conditions under which wax would precipitate,diffusion deposition experiments on dead oil to determine the contribution of wax diffusion to deposition rates under various conditions, andshear deposition experiments, also on dead oil, to determine the rate of transport of precipitated wax particles to the wall. Wax Crystallization Experiments Background. The purpose of performing the wax crystallization experiments was to determine the temperature at which wax precipitation first occurs in the wellbore (the crystallization temperature). This critical waxing temperature depends on the composition of the wax-containing fluid and therefore on the amount of gas dissolved in the oil. The oil used in this study is saturated with gas under reservoir conditions; as it flows up the wellbore, its pressure drops and gas is liberated. The wax-containing fluid therefore has a continually changing composition. Because gas in solution in the oil acts to some degree as a solvent for wax, the loss of solution gas raises the wax crystallization temperature. When the temperature at some point in the wellbore is lower than the crystallization temperature of the fluid at that location, wax will begin to come out of solution and become available for deposition on the wellbore walls. Ideal-solution theory provides a basis for a theoretical understanding of the crystallization phenomenon. According to the theory, the crystallization temperature is a function of the number of moles of solute (wax) in solution, the number of moles of solvent (live oil) dissolving it, and the melting point and latent heat of fusion of the solute. The nature of the solvent is considered to be irrelevant. The theory states that .......................................(1) Note that when the temperature drops to a point where fw, the mole fraction of wax that the oil can hold in solution, drops below the amount of wax previously in solution, wax will precipitate. The liberation of gas will contribute to precipitation by essentially concentrating the wax in solution: a given amount of wax will be dissolved in fewer and fewer moles of total solvent as gas is evolved. The model described by Eq.1 is simplistic for several reasons. First, it ignores the less-than-ideal solvation power of the oil and assumes, for example, that a mole of methane can dissolve as much wax as a mole of decane; in reality, the solubility of a higher-molecular-weight paraffin in a paraffin-based oil increases with increasing molecular weight of the solvent. Second, the model treats the wax as a single quantity when it is actually a complex mixture of components. Thus, the model is a lumped-parameter model and, strictly speaking, the latent heat of fusion and melting point have no meaning. Finally, the model does not address other phenomena that can affect precipitation of waxes. In particular, it ignores nucleation and flocculation phenomena, for which volumetric effects can be important, as well as the existence of micellar structures, which can hold asphaltic waxes in suspension in some instances, yielding an apparent solubility. Nevertheless, idealsolution theory provides a good starting point, especially because the oils in this study contained predominantly paraffinic waxes in paraffin-based oils. Equipment and Procedures. Crystallization temperatures of live oil were measured as functions of bubblepoint pressure in the filtration apparatus shown in Fig. 1. Live oil of a predetermined bubblepoint pressure was stored in an insulated piston cylinder, which was heated to reservoir temperature (191 degrees F 6 degrees [88 degrees C 3 degrees]). The oil was pumped from the cylinder through two filters in series at a pressure maintained above the bubblepoint by a backpressure regulator downstream of the filters. The first filter was of 1.2- m mesh and was maintained at about 165 degrees F [74 degrees C] by a water bath heated with an immersion heater controlled by an on/off temperature controller to 2 degrees F [1 degrees C). This first filter was used to remove any non-wax solids from the oil. The second filter was also of 1.2 m mesh and was immersed in a variable-temperature glycol bath, which could be controlled between about -20 and 160 degrees F [-29 and 71 degrees C]. SPEPE P. 121^

Summary Sand production from weak, but competent, rock as a result of high production rates is a growing concern. In unconsolidated sand, the decision to gravel pack is usually clear; however, the decision is harder in weak rock because the need for sand control often depends on the desired drawdown or production rate. Also, wells that do not initially require sand control may later become sand producers. The ability to predict at what point sand problems will occur is useful. This paper presents a method for predicting sand production in gas wells and the results of applying that method to 13 fields in the U.S. gulf coast area. The method has since been applied extensively worldwide by Arco. In the fields addressed in this paper, rock strength was determined in one or more ways: core testing, log correlations by use of direct shear velocity measurements with the dipole sonic log, or log correlations with traditional sonic logs and calculated shear velocities. Rock strengths determined by core tests and log correlations are compared. The prediction method was incorporated into a simple log analysis program that facilitates quick identification and analysis of potential sand-producing zones, and this program is discussed. Field production data are presented and compared with theoretical predictions as well as with predictions based on traditional shear failure theories. The method presented differs from commonly used log-based sand-prediction models in two important ways. It models pressure gradients in the reservoir instead of assuming that all the pressure drop occurs at the perforation face. In addition, it allows for higher drawdowns than those permitted by the shear failure criteria, up to the drawdown that would produce tensile stresses at the perforation face. The method also addresses how allowable drawdown changes with reservoir depletion, which existing models do not consider. Introduction Prediction of maximum sand-free production rate provides information for sand-control decisions and allows maximization of rate in those wells that are completed without sand control. In some fields, data, including both logs and core tests, are plentiful; but, in most, only minimal data are available for making this decision. The technique described in this paper was developed to work even with minimal data, while also taking advantage of extra data that might exist. The primary components of the method are prediction of rock strength, calculation of maximum drawdown for perforation stability, and calculation of reservoir failure. The tools are an analytical solution for hand calculation, a log analysis program for foot-by-foot analysis, and a spreadsheet for accelerating the hand calculation. We chose the analytical solution over a finite-element program because, in our experience, available data, timing, and resources generally do not justify the complexity of numerical simulation. Our goal was to have a method that would allow gravel-pack decisions to be made in the time period between logging and completion, typically a few days. The minimum information required for the analysis are a log analysis, including sonic and density logs, gas properties (temperature, pressure, and gravity), and estimates of reservoir area, thickness, and depth. With this information, a synthetic shear velocity log is generated, rock strengths are estimated from correlations, and in situ stresses are estimated from rock properties. In addition, a complete set of data would include a dipole sonic log, confined compression and tension tests on core, and fracture gradient. The more data, the less uncertainty exists about the correlations. The model predicts the onset of sand production and is not designed to apply to situations where some level of sand production may be allowable. Prediction of continuous or intermittent sand production requires a more sophisticated model, such as that described in Ref. 1. But for many situations, such as for the high-rate, high-pressure gas wells described in this paper, erosional and safety issues dictate that any sand production should be avoided. The model also does not apply to most cases in which water is produced. In a water-wet rock, flow of water, which is the wetting phase, reduces the effective cohesive strength and leads to sand production at lower drawdowns than expected. This is addressed in Ref. 1 but is not incorporated into the simple model described in this paper. Chemical interactions may also occur between the water and the rock cementation that affect sand production, and these obviously are not taken into account. Field Descriptions All the fields analyzed are sandstone reservoirs in the Texas/Louisiana region of the Gulf of Mexico, either onshore or offshore. Depths ranged from ˜4,500 to 15,000 ft. Porosities varied from ˜20% to 37%. All the wells produced gas as a single phase, with minimal water production. Rock Property Correlations Rock strength was assumed to be defined by a Mohr-Coulomb failure criterion, characterized by an angle of internal friction and unit cohesive strength. From data presented in Ref. 1, the angle of internal friction was calculated from porosity withEquation 1 From Ref. 2, the unit cohesive strength was calculated byEquation 2 where Kb and E are in millions of pounds per square inch. With these correlations, comparison of the predicted values with measured values are presented in the case studies below. In general, agreement was good. The angle of internal friction correlation is better for high stresses away from the perforation. At the low stresses around the perforation, the angle of internal friction may be higher than predicted owing to nonlinearity of the Mohr envelope.

The conditions necessary for stability or failure of a spherical cavity in unconsol idated sand or weakly-cemented rocks have been studied. Experiments using physical model shave util ized weaklycemented synthetic, porous rocks.As externa 1 confining pressure was applied to the rock, a shear failure region was induced around the cavity. When fluid flowed through this system at increasing rates, the outer boundary of the shear failure zone was calculated to have increased, and a region of disaggregated solids was created adjacent to the cavity.

Summary When hot oil is produced through closely spaced wells that penetrate a permafrost zone, large thawed regions can be created. Thawing initially produces a sudden, large decrease in permafrost pore pressure; this results in compaction of soil and strain in the casing. Induced pipe strains initially increase with time as the thaw front expands. Later, water flows into the thawed region from above and below the permafrost and repressures the pore space. Repressurization limits the induced casing strain, thus permitting the selection of adequate permafrost casing from a number of conventional casings. Introduction Heat lost from Prudhoe Bay wells warms the adjacent permafrost, causing it to thaw. As the ice in the pores of the permafrost melts, the volume decrease causes an immediate and severe drop in the pore pressure. The change in pore pressure causes the thawed permafrost to compact and subside, inducing compressive and tensile strains in the well casings.' For a given permafrost lithology, the magnitudes of the induced strains depend primarily on two parameters: the extent of thaw, and the pore pressure decrease. Infill drilling on existing Prudhoe Bay pads can result in substantial savings in gravel pad and flow line costs when compared with extending the pads or building new ones. When new wells are placed near existing ones, however, the thawed zones around individual wells can merge to form a much larger thawed region. The larger thawed region tends to increase casing strains and surface subsidence. These effects are offset, however, by the tendency for the fluid in the thawed permafrost to be naturally repressured by the influx of water from the surface and from below the permafrost. This paper describes new procedures which permit the calculation of water influx and the resulting pressures within the thawed zone. The water influx is significantly influenced by the extent (area) of thaw and the rate of growth of the thawed area. The resulting casing strains, in turn, depend on both the extent of thaw and the amount of water influx. The mechanical problem is thus intimately linked with the heat transfer problem. To evaluate the new procedures, pore pressures calculated using the new method were compared with pore pressures measured during a Prudhoe Bay 5-spot field test conducted in 1973-1974. Agreement between measured and calculated pressures was good. The mathematical method was then used to calculate expected behavior for two base cases of infill drilling. Studies quantified the sensitivity of repressurization to lithology variations. A substantial amount of repressurization was found to occur, especially near the top and bottom of the permafrost. Repressurization reduces casing strain, makes the selection of an acceptable surface casing tractable, and thus makes infill drilling feasible from the thaw and casing-strain point of view. THAWING OF PERMAFROST AROUND WELLS In ARCO's operating area at Prudhoe Bay, wells are typically drilled along pairs of parallel rows. The spacing between rows is approximately 175 feet. Currently, wells are drilled along each row on 120-foot spacings. After a first round of infill drilling, well spacing along each row would be reduced to 60 feet. After a second round, well spacing would be reduced to 30 feet. Extents of thaw were calculated for two well configurations, both for parallel rows with row-to-row spacings of 175 feet. One configuration used a well-to-well spacing of 60 feet; the other, 30 feet. The projections of thaw for these two configurations were calculated using a 2-dimensional model. P. 181^

Summary In some applications, complete separation of liquid and gas is not required, and it is sufficient to remove only a portion of the gas. One example is separation of gas from one well for raw gas lift of other wells. This can be done either on the surface or downhole The auger separator is a new device that was initially developed to fit inside production tubing, and so is an ultra-compact separator design. It differs from other separators in that it requires no complex controls or power to operate, and, for most applications, has a diameter of only a few inches. The multiphase fluid enters an auger section where the pitch of the stationary auger blade causes the flow to rotate. Centrifugal forces created by this rotation cause the liquid to flow along the outer wall with the gas flowing in the center. A portion of the gas is ported through a crossover to the annulus in downhole applications or to a gas line in surface applications. The downhole separator is placed by wireline in the tubing. The surface version is placed as a spool piece in the production line. Equations were developed to predict performance and were incorporated into a spreadsheet for ease of design. Laboratory tests were performed to validate the predictions and to explore various design details. Following successful lab testing, the prototype separator, which was 3-1/2 inches in diameter, was placed downhole inside 4-1/2" tubing. The separated gas was ported to the annulus through a gas lift mandrel. This test showed that the equipment could be placed in the well with wireline that downhole separation was feasible, and that the theoretical pressure drop calculations were accurate. Following this test, an 8-inch diameter auger separator was designed for separation of gas on the surface, as a full scale pilot test. This was placed in the production line from a well, and the separated gas was used to provide raw lift gas for other wells on the drillsite. These two field tests showed that partial separation was feasible with this device, and that the equations used for design were reasonable. The surface auger separator was left in place after the test, and continues to provide lift gas. This paper presents the concept, design equations, lab test results, and field test results of both a downhole and surface application. Other potential uses are also discussed. Introduction Conventional separators are normally large vessels with elaborate control systems to maintain levels. Those designs have evolved from applications where 100% separation is desired. However, there are many instances where a relatively dry gas will suffice, so that complete separation is not required. In those applications, much simpler and more compact designs are possible. One such application is raw gas lift, where some liquid carryover can be tolerated. By using a well on the drillsite as a source well, gas lift can be provided to other wells without the need for expensive gas supply lines or processing equipment. This greatly improves the economics for gas lift. The rough separation of gas can be done on the surface if the surface pressure of the supply well is high enough. But if the surface pressure is not high enough, this separation can be done downhole The advantage of downhole separation is that a higher gas pressure can be achieved if the gas is not subjected to the frictional and head pressure drops produced by the more viscous and dense liquid phase. This is avoided when the separated gas is allowed to flow up the annulus. The downhole application was conceived and developed first, and it was the small size required for installation in tubing that led to the compact installations that were later achieved on the surface. To be feasible, the downhole separator had to be compact enough to be installed and retrieved on wireline inside 4-1/2" tubing, require no power or complex controls, and have no moving parts. All of these attributes turned out to be attractive for surface separation as well. The device which we developed and describe below met all of those design goals.