Showing papers presented at "Formal Methods in 1973"

An Evaluation of Acid Fluid Loss Additives Retarded Acids, and Acidized Fracture Conductivity

Abstract: An evaluation of acid additives and retarded acid systems indicates that the stimulation resulting from acid fracturing can be increased when effective fluid loss additives are used in HCl, or when the acid viscosity is increased significantly. Acid emulsions were found to have a low fluid loss rate and to be retarded; whereas, oil wetting surfactants gave no retardation at typical field injection rates. Conductivity studies show that, in general, the fracture flow capacity resulting from acid reaction is very high, except when rock embedment strength and/or rock solubility is low, or the closure stress is high. (11 refs.)

The Importance of Joule-Thomson Heating (or Cooling) in Temperature Log Interpretation

Abstract: This study shows how knowledge of the Joule-Thomson effect can aid temperature log interpretation. The effect is a cooling of produced or injected gas, or a warming of injected water, due to pressure drop in flow through the formation and perforations. This influences shut-in temperature behavior, and thus is important in temperature log interpretation. A key conclusion is that the shut-in temperature profile is influenced not only by the previous flow rate profile, but also by the permeability profile. Methods for quantitative interpretation (i.e., determination of injection rate profiles) are reviewed, in light of this conclusion. (22 refs.)

Effect of flow rate on stability of unconsolidated producing sands

Abstract: Stabilization of unconsolidated sand during production by sand arching was confirmed with a sandpack model of a well completion. Fluid was flowed radially through a sand pack which was loaded vertically to simulate overburden pressure. Flow rates were gradually increased to the point at which sand flowed and the arch then examined. Larger arches resulted from higher flow rates. Critical rate for the sand production depended on rate history as well as rate magnitude and arch size.

Numerical Simulation of Carbonated Waterflooding In A Heterogeneous Reservoir

Abstract: The purpose of this study is to report the development of a numerical model that can be used to predict the reservoir behavior of a carbon dioxide flood in a heterogeneous reservoir. The mathematical model is based upon the transport equations that describe the 2-dimensional, simultaneous flow of 3 phases--oil, water, and COD2U. Solubility of the COD2U in both water and the development of a free COD2U phase are allowed. This mathematical model is subject to the following assumptions: (1) 2-dimensional, time- dependent flow/ (2) no free hydrocarbon gas exists in the reservoir/ (3) solubility of COD2U in each saturated phase is a function only of pressure/ (4) phase equilibrium between oil and water containing COD2U is instantaneous/ and (5) oil and water become saturated with COD2U simultaneously.

Displacement of a Micellar Slug Foam in Unconsolidated Porous Media

Abstract: A comparison of a micellar slug driven by a foam versus by a polymer flood was made. The aqueous slug contained Floodaid 130 and brine (2 percent sodium chloride). Foam was generated from an aqueous brine solution of Triton X-100. The polymer flood was Dow Chemical's P-700 in the brine. Sand packs (porosity 39.4 percent, permeability 23.6 d) were saturated with the brine and flooded with 32.5/sup 0/ API California waxy crude oil. For secondary oil recovery, the slug-foam treatment obtained about 25 percent less of the original oil in place than the slug-polymer treatment. However after waterflooding with the brine, tertiary recovery by the slug-foam treatment was only about 8 percent less than the amount obtained by the slug followed by a polymer flood. Hence, tertiary oil recovery using a foam drive fluid could be economically attractive since less foaming agent than polymer is required.

Emulsion Flooding of Viscous Oil Reservoirs

Abstract: Stable water in oil emulsions can be formed with low pH water and viscous crudes which contain natural emulsifiers. An example is Boscan crude oil (200 cp) which is an asphaltic crude. Consolidated sandstone cores (about 19 to 22 percent porosity, 200 to 500 md permeability) were flooded alternately with Boscan crude and Boscan reservoir water (130 ppM sodium ions, 8 ppM calcium and magnesium ions) at reservoir temperatures, 180/sup 0/F. Secondary recovery tests were performed at 180/sup 0/F by following a crude flood with an emulsion slug, a polymer (Dow Pusher 700) flood and a water drive. All emulsion and polymer solutions were prepared with distilled water. A maximum oil recovery of 97 percent was obtained by emulsion flood. A waterflood gave a maximum recovery of 42 percent. Tertiary oil recovery, an emulsion flood after waterflooding, yielded 75 percent of the residual oil.

Application of Sparse Matrix Techniques to Reservoir Simulation.

Abstract: Publisher Summary This chapter discusses the application of sparse matrix techniques to reservoir simulation. It presents computing time requirements of sparse Gaussian elimination for some typical problems of reservoir simulation. In many reservoir simulation problems, the solution of a system of nonlinear parabolic partial differential equations describes multiphase flow in two or three space dimensions. The chapter focuses on two-dimensional problems. The most common technique is to approximate the domain by a rectilinear mesh or grid and to approximate the partial differential equations by five point difference equations together with suitable linearizations. In reservoir simulation, systems of the form have usually been solved with iterative rather than elimination methods. This saves both time and storage. However, selecting an efficient iterative method, optimal acceleration parameters, and a good stopping criterion is difficult and expensive. It has been found that in some situations, iterative methods do not converge to an acceptable solution within a reasonable number of iterations because of the increasing complexity of simulation problems.

Method for Automatic History Matching of Reservoir Simulation Models

Abstract: Instituto Mexicano del Petroleo has developed an efficient method for automatic adjustment of reservoir simulation models to match field performance. The best methods up to now could not be efficiently applied to reservoirs that include a large number of wells and/or a large number of pressure measurements in each well. As the size of the reservoir is increased, the number of zones and the number of errors are increased considerably so that adjustments by linear programming techniques become more and more time-consuming. The IMP method presented requires several random simulation runs and is applicable to large reservoirs. Furtherfore, it offers the following advantages: (1) It does not require a previous zonation of the parameters adjusted, (2) it includes standardization of matrices of differences between calculated and observed values of the control variables as well as judicious weighing of the errors, (3) it considers a nonlinear objective function, and (4) for minimizing the objective function, a direct search method is used that hardly requires memory or computer time. The proposed method has been applied to constructed and actual gas reservoirs where pressure was used as a control variable. Also, it was applied to a constructed 2-dimensional 3-phase reservoir where pressure andmore » gas/oil ratio were used as control variables. In all cases, very good agreement between actual and calculated values was obtained for porosity and permeability, the parameters considered in the matching process.« less

Fluid Loss Additive Seriously Reduces Fracture Proppant Conductivity and Formation Permeability

Abstract: Fracture proppant conductivity can be severely impaired by certain fluid loss additives. Laboratory tests show this reduction in conductivity is frequently more than 50%, which tends to nullify any effect of fracture extent beyond a few feet from the well bore. Oil-soluble additives appear to be a possible solution to this problem. Other experiments indicate that formation permeability is severely reduced at high differential pressures. This damage to permeability would seriously impair the productivity of any zone which was not fractured. (14 refs.)

Ten Years' Experience with Sour Gas Production in Germany

Abstract: The sour-gas production in W. Germany and especially the problem of tubing string plugging by precipitation of elemental sulfur is described. The main trouble results from elemental sulfur dissolved or chemisorbed in the sour gas. It is intensified by the lack of condensable higher hydrocarbons in German sour gas. Remedies against sulfur plugging are critically examined. Up to now, only liquid sulfur solvents have been found suitable for economic sour-gas production under German conditions. Different solvents, their properties, their advantages and disadvantages are mentioned. Experience in Germany with the 2 main types of sulfur solvents, e.g., high boiling aliphatic hydrocarbons and aqueous alkali sulfide solutions are described and discussed. Both processes applied in Germany have their distinctions and drawbacks. Additional problems may rise with decreasing reservoir pressure and influx of formations waters. (20 refs.)