Zohoorian, A. H. (Petroleum University of Technology) | Moghadasi, J. (Petroleum University of Technology) | Abbasi, S. (Research Institute of Petroleum Industry) | Jamialahmadi, M. (Petroleum University of Technology)
Water injection is applied as a well-established process in different reservoirs for pressure maintenance and oil recovery enhancement in the petroleum industry. Scale formation is a common challenging issue in the water injection process. In this paper, mixed salt scaling, especially that of the typical sulfate salts, is studied.
Scale formation is resulted from incompatible interactions between the injection and formation water. Precipitation of the unwanted solid materials on a surface is responsible for some problems as the formation damage, and short life of the completion equipment and surface facilities. In this experimental study, through static and dynamic tests, co-deposition of various salts during water injection is examined. Static tests are performed so as to obtain properties of the mixed salt precipitation. Further dynamic tests are conducted with different variables like the pressure, temperature, concentration, and the degree of salinity.
Several studies conclude that the success of the water injection process is mainly dependent on both fluid-rock and fluid-fluid interactions. They have also mentioned the coexistent precipitation of the salts in the water systems; nevertheless, the referred studies focus on the single salt than mixed salts due to the complexity of the process. Permeability reduction is affected by different parameters such as the mixing ratio of the injected water to the formation water, concentration, salinity, temperature, pressure, pH, and injection rate.
This research is carried out in realistic conditions so that the permeability reduction is precisely and appropriately measured by well-designed equipment. This study considers the mixed salt composition which could give a better insight into the permeability reduction than the former works, especially those which only investigated the single salt scaling. At last, a better understanding of the mechanism of inorganic scale deposition on the rock surface is provided.
Removal of scale depositions from wellbore tubulars has always posed a challenge to operators. Traditional methods to do so have included chemical treatments, mechanical methods, or even removal of affected tubulars. All of these methods have varying degrees of success, as well as varying cost to operators depending on the type and amount of deposition in the tubulars.
Barium Sulfate scale removal has traditionally posed the greatest challenge to operators and service companies alike. Chemical soaks have been developed and applied as well as mechanical methods, usually meeting with limited success. As a result of these failures, a dependable, engineered and cost effective approach has been developed. The process combines the use of traditional coiled tubing operations and a high-pressure rotary jetting tool to remove the Barium Sulfate scale - without use of solvents. The process has been successfully utilized to completely remove over 9,000' of Barium Sulfate scale in subject wells that have not been effectively cleaned when tradition methods have been tried.
This paper will look at well conditions conducive to the formation of barium sulfate scale, as well as why it is such a difficult material to remove. Coiled tubing solutions will be discussed, culminating in a collection of case histories where a unified mechanical / jetting program has had best results.
An extensive research programme was launched with the aim at evaluating the potential of seven different polyamino carboxylic acids (PACAs) using both technical and economic aspects. Dissolving capacity of each compounds was determined under equilibrium conditions as a function of concentration for barite and reservoir rock (sandstone). The absolute and relative selectivity of dissolution, viz. the matrix effect of formation rock were precisely analyzed. Dissolution of barium sulfate, calcium and magnesium carbonate and iron compounds was followed in time, and thus, the kinetic calculation could also be made.
Results of the research programme provided reliable data for comparison of dissolution capacities under identical chemical (equilibrium, kinetic, dissociation, etc.) conditions. On the basis of the experimental findings it was concluded that the sequence of dissolution capacity is different if the results were evaluated in technical or economic senses. It was also shown that the preferentially used compounds (e.g. DTPA, and particularly EDTA) are not the best choices when technical considerations are only enforced. The economic grounds, however, may partly justify their application at the expense of poor efficiency. The systematic analysis of the mentioned dissolvers may open new vistas in mitigation of formation damage caused by barite or barium sulfate scales and accelerate the search for more effective mixtures of complex-forming agents to be applied under field conditions.
Deposition of barium sulfate in surface facilities at the Saratoga field (Texas) has been recognized nearly a hundred years ago. In the middle of the thirties it was also realized that precipitation of scales may take place not only in the bottom hole or the production tubing, but also in the vicinity of wells causing the well known formation damage. In the same time substantial amount of knowledge in physical chemistry has been accumulated which gave satisfactory explanation for solid phase formation from homogeneous solutions. The supersaturation, seed formation and crystal growth as subsequent steps of scale formation are still regarded as main elements of the unfavorable process. In the mean time detailed analysis of factors influencing the side reactions and part processes contributed significantly to better understanding of mechanisms, but the information obtained opened also new vistas in predicting and controlling the precipitation of different materials from formation water.
In practice of the hydrocarbon production the "scale" or "injectivity/producibility" problems have always been omnipresent and hence, a great deal of efforts had been made in the past decades to prevent scale formation or to develop efficient technology to remove the precipitated solids if they already formed. Therefore it is not a surprising remark, as Sloat1 stated as early as 1963, that the scale inhibitors are the real "work horses" of the industry and without organic phosphates type well packing a stable production rate can not be maintained at most of the oil fields. Although the application of scale inhibitors has started much earlier in karstic formations2,3, blocking of seeding or crystal growth by these compounds remained effective for different types of scales until now. On the other hand, it is also evident that acidization serves the same important purposes in alleviation of formation damage if acid soluble compounds, usually inorganic scales are responsible for deterioration of injectivity or producibility in wells. These two techniques, inhibition or dissolution of scales, still represent fundamental technologies in oilfield service and they are the most frequently applied stimulation techniques in both continental and off-shore fields.
The formation damage may ensue already during drilling. Recently, extension of exploration and drilling activity towards greater depth, and as a result, application of weighing additives more widely, increase logically the danger of formation damage. It is true that partial replacement of barite with acid soluble materials may offer a temporary solution, but on the other hand, the colloidal barite having numerous advantages over other mud components, might result worsening situation.
Field tests of various thermal enhanced oil recovery processes in the thin reservoirs of the Saratoga field in southeast Texas are in progress. The primary objective is to evaluate recovery and progress. The primary objective is to evaluate recovery and economics for each of: dry in-situ air combustion, wet in-situ air combustion, and steamflooding, to determine the optimal process.
The Saratoga field is one of many piercement type saltdomes located along the U.S. Gulf Coast. The field contains numerous Miocene sandstone stringers, averaging 20 feet in thickness and ranging in depth from 150 to 1900 feet, from which approximately 17% of the original oil-in-place has been produced by primary methods. The reservoirs contain low to medium gravity (14-22 degrees API) crude, with moderate to high viscosity (100-1000 cp), which make secondary recovery by a process such as waterflooding highly unfavorable. Thermal recovery processes were initiated in this field in the early 1970's; eight fireflood projects have been completed, while four wet in-situ air combustion projects and one steamflood project are ongoing.
Evaluation of these projects will provide a basis for the application of the appropriate thermal recovery process in thin, shallow reservoirs, typical of the Gulf Coast.
The potential of thermal recovery was first realized as early as 1920 when downhole heaters were used to introduce heat into reservoirs. The first published large scale field operations of the underground combustion process were carried out in the USSR in 1933, with the first reported U.S. field application in 1942 . Steam drives were introduced in 1931-32, when steam was injected into a reservoir at a depth of 380 feet near Woodson, Texas.
Thermal technology has developed rapidly in the U.S. since the 1930's and 40's. The heaviest concentration of effort has been focused on the large heavy oil reservoirs in California and Canada. It has been in these areas that thermal recovery technology has been developed, tested, and proven. From these tests industry has established certain criteria for design of thermal recovery projects. However, as that technology is carried outside the confines of these areas, refinements can be made to these design and economic criteria. As an example, the general design criteria for steamflood candidates typically include a reservoir net pay "cut-off" of 30-50 feet. However, steamflood projects are being successfully conducted in thinner reservoirs throughout the U.S..
This paper briefly discusses the performance and comparative economics of three thermal recovery processes in the same reservoir: dry in-situ air combustion, wet in-situ air combustion, and steamflooding.
DEVELOPMENT AND PRIMARY PRODUCTION
The Saratoga Field, located in Hardin County, Texas 90 miles northeast of Houston, was discovered in 1901 with oil production from a depth of 995 feet. Mobil obtained its acreage position in the field through the acquisition of General Crude in 1979.
The initial development period ended in 1923, with a peak production rate of 20,000 bopd from 884 wells. The main production production rate of 20,000 bopd from 884 wells. The main production was from the Miocene sand series, in stringers from 1200 to 1900 feet. After 1923, there were several periods of small scale development in numerous Miocene stringers with minor production response. Primary production has since declined to the current level of Primary production has since declined to the current level of approximately 700 bopd, with an average decline rate of 18 percent per year. per year. The primary recovery mechanism in these Miocene reservoirs is pressure depletion with some gravity drainage, yielding a primary pressure depletion with some gravity drainage, yielding a primary recovery of 17%.
The Saratoga Field is one of many piercement type salt domes located in the Yegua Trend of southeast Texas. The source of the oil is apparently Frio sediments located basinward of the domes . The salt dome at Saratoga is approximately 1 1/4 miles by 2 miles, with the depth to the caprock between 1500 and 5000 feet. Production is shallow (less than 2500 feet) and is localized on top Production is shallow (less than 2500 feet) and is localized on top of the dome.
This paper was prepared for the Eastern Regional Meeting to be held in Columbus, Ohio, November 8-9, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
Many areas of the United States are suitable for the underground storage of hydrocarbons from both a geologic and an economic viewpoint. This potential for underground storage has not been explored or developed to any great extent along the eastern seaboard, although the need for underground storage continues to increase.
A growth in demand for clean fuels and changes in the availability of domestic natural gas supply for the eastern seaboard point to a present need for evaluating the potential for underground storage of gas supplies from other sources. Specifically, aquifer storage facilities for natural gas derived from domestic or imported sources and from increasing imports of liquefied natural gas, should be developed for both curve-shaping and peak-shaving requirements. This aquifer storage could be used to meet increasing gas demands resulting from population growth, particularly in inland areas excluded particularly in inland areas excluded from ready deliverability provided by LNG vaporization facilities. In addition, the same aquifer storage facilities could find a future use in handling supplies of gas from domestic synthetic natural gas.
Cavern storage of LPG or reformed products for the northeast should also products for the northeast should also be developed. Cavern storage would handle increased demands for products such as propane, butane, naptha, fuel, oil and propane, butane, naptha, fuel, oil and crude. The total potential for cavern storage has not been adequately assessed in terms of future needs.
The technical feasibility of both aquifer and cavern underground storage depends largely upon geologic conditions. The economic feasibility can readily be estimated by comparison with other storage operations. An analysis is made of existing geologic conditions (on a regional basis) and specific recommendations are made relative to the development of underground storage facilities along the eastern seaboard.
Methods of studying oilfield mineral scale deposition in the laboratory do not work for barium sulfate because only small nonadhering crystals are formed. On the other hand, barium sulfate scale found in down-hole or surface equipment is strongly adhering and may contain very large crystals. Results suggest that most of the difference derives from the extremely low solubility of barium sulfate. Firm adherence of scale and the consistent development of oriented crystals 100 microns and larger suggest a relationship between scale adherence and crystal growth. Data from this study indicate some reasons for barium sulfate's occurring as a deposit in oilfield waters. The unique characteristics as well as the associative properties of barium sulfate scale as related to calcium carbonate and calcium sulfate are shown.
The first observed deposition of barium sulfate scale in oilfield production equipment is unknown but probably coincides closely with the beginnings of the oil industry itself. Moore described barite oolites in some producing wells in the Saratoga field, Tex., in 1914. Currently, positive identification of barium sulfate deposition is recorded in most of the major oil-producing areas of the United States. As efforts continue to identify the composition and functions of the materials found in scale deposits. the geographic and economic importance of the part played by barium sulfate will become even more important. This belief is based on the following facts. 1. Many oil fields in the U. S. are in or entering their mature phase and the volume of produced water is increasing; thus, the cumulative effects of low-solubility minerals become more significant. 2. Secondary recovery techniques and increased emphasis on waste disposal systems require controlling the behavior of all constituents of water to prevent formation plugging. 3. The more general use of instrumental analysis has reduced the time and improved the accuracy of complete scale and water analysis. 4. Once formed, barium sulfate scale is resistant to present methods of chemical removal; therefore, costly mechanical methods are necessary. Thus, new methods of prevention and control will require specialized chemical techniques and better knowledge of the causes of scaling. Consider the results of some simulated field deposition studies illustrating this need (Fig. 1). The studies utilized a Scale Deposition Test Cell* and each coupon was exposed to 8,000 ml of a 300 me/liter solution of the various types of mineral scale. All tests were conducted at 140F. Only the calcium sulfate and calcium carbonate deposited scale. The solution containing 300 me/liter of barium sulfate exhibited copious amounts of precipitate, but none of the precipitate adhered. The fluids from the effluents were also allowed to impinge on glass slides. Fig. 1 shows the relative adherence of the three types of scale on unetched glass. The barium sulfate failed to deposit in the same manner as the calcium carbonate and calcium sulfate solutions.
The application of the hydraulic fracturing process in the Annona Chalk formation in the Caddo-Pine Island field, Caddo Parish, La., has created a new outlook on the development of this reservoir as an economic source for oil production. The reservoir has been greatly affected by faulting and/or fracturing during its geologic history, and the physical characteristics of the formation have made possible the successful hydraulic fracturing operations. These conditions have also caused the production to vary greatly between wells and have resulted in several different methods of drilling and completion practices by the operators.
This paper describes briefly the geology, development history, present drilling and completion practices, and the results of the hydraulic fracturing process in stimulating the production from this reservoir. In order to show results of the various completion techniques, production histories on several wells are presented and comparisons of the production from individual or groups of wells before and after fracturing operations are discussed.
The Caddo-Pine Island field is located approximately 15 miles north of the City of Shreveport in Caddo Parish, La., and Marion County, Tex., and is shown geographically in Fig. 1 which covers a portion of the Ark-La-Tex Area. Although production has been obtained from several horizons, ranging in depth from the Nacatoch sand at 800 ft to the Hosston or Travis Peak which is found at 2,500 ft near the crest of the dome of the Lower Cretaceous beds, this paper will deal mainly with the development and production of the Annona Chalk reservoir.
The production from the Chalk is associated with faulting and natural fracturing of the formation and is found in several fields in North Louisiana. The discovery well in the Caddo-Pine Island field was the Savage Bros. & Morrical No.1 Offenhauser, which was completed March 28, 1905, in the Annona Chalk at a depth of 1,556 ft. The well was located near Oil City, La., in the center of the NE ¼ of the SW ¼ of Sec. 1, T20N, RI6W, and had an initial production of 5 B/D of 34° gravity oil. The well was considered non-commercial by the operators and was soon plugged and abandoned. However, this discovery led to further development. By the close of 1907 23 wells had been drilled -eight of which produced oil, 11 produced gas, and four were abandoned. Development of the field continued at a rapid pace during the following years, and by 1918 the production reached a peak of 11 million bbl/year.
To the southward, in Central Mexico, very complete sections are found of both Trias and Jura, but if the waters of those periods ever reached the Texas coast, no evidence now remains to prove it. During the Cretaceous, however, the southern seas did cover a part of the Texas area, and the sediments of its earlier period (the Lower Cretaceous or Comanche) in'the two areas are closely related. They consist of sands, clays, and limestones, which in the coastal area present little, if any, evidence of being oil bearing. The beginning of the Upper Cretaceous deposition marked a very decided change in this respect and ushered in a period in which the formation and deposition of petroleum or petrolic matter was widespread through the coastal area. They form the top of the Middle Cretaceous deposits of the Mexican classification and are overlain by shales and marls of their Upper Cretaceous.