Absolute Open Flow Potential Research Articles

Washington Ranch Morrow Field: Case History in Frontier Exploration: ABSTRACT

The Washington Ranch Morrow gas field is located 35 mi (56 km) southwest of Carlsbad, New Mexico, on the western rim of the Delaware basin 6 mi (10 km) basin-ward from the Capitan reef front. Late Pennsylvanian orogenic forces created a structural development of such sharp magnitude that most exploration outlook condemned the area as too disturbed for commercial hydrocarbon entrapment. The northwest-southeast-trending fault on the northeast side of the field has a displacement of more than 2,000 ft (610 m), structural contours on the basal Morrow sandstone unit define 600 ft (183 m) of closure against the fault. The crest of the structure has lost 1,700 ft (518 m) of Wolfcampian and Upper Pennsylvanian section through erosion and nondeposition. Eight deep dry holes had been drilled within an 8 mi (13 km) radius of the drill site for the discovery well. Several of these wells had encountered a significant igneous sill only 400 ft (122 m) below the basal Morrow sandstone. The presence of this sill so close to the main potential reservoir rock further detracted from the prospect. Reefing development of two separate ages in Pennsylvanian sediments caused very rapid lateral facies changes which made well log correlations difficult. Frontier exploration philosophy and technique were employed to overcome the many negative considerations of the prospect. The discovery well was completed in June 1971 for a calculated absolute open flow potential of 54 MMCFGD natural, through Morrow perforations at 6,795 to 6,806 ft (2,071 to 2,074 m). While drilling was in progress gas flowed at the rate of 22 MMCFGD on a 2-hour and 10-minute drill-stem test from 6,791 to 6,860 ft (2,070 to 2,091 m). Major gas reserves were made available to the pipeline with the drilling of nine development wells. End_of_Article - Last_Page 766------------

Estimation of Well Permeability for Use in Single Phase Gas Reservoir Production Simulation

Of all of the reservoir data necessary for use in mathematical reservoir simulation, the permeability value is usually the least known and most difficult to obtain. A previously published correlation has been used in estimating permeability values for wells in a tight, single phase gas reservoir. These values were used in a mathematical model, along with other better known reservoir data, to match past performance and predict future performance of individual wells. predict future performance of individual wells. Reasonably satisfactory results were obtained with a minimum number of runs. Computer time is believed to be considerably less than that which would have been required if the correlation had not been available. There are several occasions when permeability values can be successfully estimated for simulation projects without benefit of individual well core projects without benefit of individual well core analysis or pressure test permeability data. The method described here involved use of a correlation presented as Fig. 2 (see Fig. 1) in paper SPE 1555 by L. E. Harlan. It is a log-log plot of adjusted absolute open flow, times 1,000, divided by initial shut-in tubing pressure squared vs known productive capacity (Keh) pressure squared vs known productive capacity (Keh) for 22 gas wells. The 22 data points are from "skin free" wells in carbonate, sand, and conglomerate reservoirs in four basin areas in the U. S. The paper describes adjusted absolute open flow as a well's calculated wellhead absolute open flow potential based on test data after 1 year of production. Justification for construction and application of the correlation is contained in the paper and will not be discussed here. The correlation was used in this study for estimating productive capacity (Keh) for 25 wells in the 2,033-well Blanco Mesaverde gas field in Northwest New Mexico. Adjusted absolute open flow for the wells was calculated from the New Mexico Oil Conservation Commission deliverability test taken 12 to 24 months after a well was placed on production. Permeability was obtained from the correlation-derived Permeability was obtained from the correlation-derived productive capacity through application of net productive capacity through application of net effective pay for a particular well. In the simulation work, predicted capacity was compared with actual capacity at a particular cumulative production point. For nearly all of the wells modeled, a satisfactory match was achieved without necessity of changing permeability. P. 1389

A Study of Stimulation Results of Ellenburger Gas Wells in the Delaware-Val Verde Basins

Abstract A statistical study of deep Ellenburger gas wells in the Delaware-Val Verde basins of West Texas has indicated a new evaluation method for use in analyzing these gas well completions. Summation of calculated open-flow potential tests on drillstem tests can be used to estimate the ultimate calculated absolute open-flow potential (CAOFP) of a well. Statistical data indicate the most favorable results are obtained with relatively small volume acid treatments (25,000 gal or less). Introduction Recent acceleration of deep Ellenburger gas well activity in the Delaware-Val Verde basins has evoked many questions as to the best methods of stimulation and the evaluation techniques available to the industry for this type of well. Because of the deep, expensive drilling and the associated high completion costs, a method of comparing stimulation results was needed. A technique is proposed that makes use of limited data such as one flow rate on a drillstem test or one flow rate prior to stimulation. By estimating a calculated open-flow potential from this one point, it is possible to estimate results from completion and stimulation. The technique of estimating the CAOFP from the one flow rate offers a tool of comparison to the geologist as well as the engineer. From scout data, the estimated CAOFP on various gas wells in isolated areas may be evaluated where it is difficult to obtain a comparison using flow rates through different choke sizes and with different flowing pressures. Data for this study were obtained from CAOFP tests from the Railroad Commission of Texas and from scout reports. In all, 45 wells in eight Ellenburger fields, ranging in depth from 13,000 to 22,000 ft, provided sufficient information for this study. Procedures for Data Analysis Previous evaluations of results in treating gas wells were based on a comparison of deliverability tests where these data were available. To make this type of comparison, all wells evaluated would have to be tested at one common backpressure, i.e., 1,000 psi surface pressure. These types of data are not available on enough wells to permit any type of statistical analysis using a large number of randomly selected wells. Since, in gas wells, the accepted measure of a well to produce is the CAOFP, which is the flow calculated with 0 psi backpressure at the formation face, the CAOFP then is the basis of comparison used in this study. Upon establishing a basis of comparison, well data were examined in the Brown-Bassett, Coyanosa, Gomez, Hamon, JM, Puckett, West Waha and Worsham-Bayer fields. Because few companies obtained tests under natural conditions prior to stimulation, it was necessary to examine drillstem tests as an indication of the capacity of a Well to produce. Therefore, the assumption is made for this study that the CAOFP of each zone drillstem tested within the Ellenburger is additive with other sections tested in the well. The sum of all the flowing DST's indicates the natural flow capacity of the well. This addition assumes no over-lapping of productive intervals or interflow between productive intervals. Another premise is that untested sections were indicated to be nonproductive when penetrated. Since in most cases where data were available only one flow rate was obtained on the DST, a slope parallel to the final slope obtained on the four-point test was used to determine the CAOFP of any given DST or flow rate with one point. Several methods can be used to determine the flowing bottom-hole pressure required to give the one point for constructing the line for the CAOFP. Flowing bottom-hole pressure can be calculated from flowing surface pressures with the method used by the Railroad Commission of Texas or one published by Guerrero. These and other methods take into consideration producing rate, gas gravity, average producing depth, tubing size and flowing temperature and pressure. These methods of calculating flowing bottom-hole pressures or bottom-hole pressures obtained from flowing drillstem tests can be utilized to determine the CAOFP of a well or zone. Previously it has been necessary to try to account mentally for differences in choke size, flowing surface pressure and rates. JPT P. 1017ˆ

A Proven Gas-Well Completion Technique for Higher Deliverability

Abstract An investigation was initiated into the mechanics of gas-well perforating because of a number of cases of drastic increases in productivity of gas wells after reperforating the same interval. Since these reperforations were with gas at low pressure in the wellbore, a test series was set up in a flow laboratory to investigate the factors involved. Berea sandstone was perforated with gas, kerosene as a formation fluid. Tests were made over a wide range of pressure differentials both to the formation and in the wellbore. The results of the test series show that the fluid pressure conditions in the wellbore at the time of perforating are much more important for gas-filled than for liquid-filled formations. For liquid-filled formations no plugging occurred in the cores tested that could not be removed by fluid flow from the core. A practical completion technique has been developed and put into practice to control the environmental conditions while perforating gas wells. Introduction Many gas wells do not come up to expectations of deliverability based upon open-hole drill-stem tests or by comparison with other wells completed in the same reservoir. This discrepancy between expectations and actual deliverability is more common with gas wells than with oil wells. High damage ratios, indicating severe skin damage, are also quite commonly observed in gas wells which have been completed with the "normal" completion methods, where wellbore pressure is maintained above reservoir pressure at the time of perforating. In many states, gas-well daily allowable is based on absolute open-flow potential. With the rapidly increasing demand for gas at more attractive prices and a ready market. it becomes much more important to obtain the maximum potential and deliverability from each well completed in a reservoir. Evidence of Poor Completions in Gas Wells Gas wells, which in comparison to nearby wells had not potentialed at a satisfactory rate, have often been reperforated. High-pressure control equipment was placed upon the well-head and entry made against pressure with a through-tubing gun. The new perforations were usually in the same interval as the original perforations, and the results were vastly improved potential tests for the well. The consistent success in improving deliverability of these gas wells indicates that the "normal" completion technique produced results which were inferior to the technique used in reperforation. A factor in the reduced deliverability of gas wells is apparent in the problems associated with blast joints. Numerous observers in the field and in the technical literature have repeatedly pointed out that where a blast joint is employed, seldom more than one to four shiny spots or holes are ever seen on the blast joint, regardless of the number of perforations in the casing. This indicates, of course, that from one to four holes produce the entire amount of gas coming from this upper completion. Presumably the normal completion technique left the remainder of the perforations ineffective. Several laboratory investigators have simulated the normal oilwell completion technique of wellbore pressure higher than formation pressure and an extended time of filtration into the formation after perforation. The tests showed that the flow efficiency of the perforations was reduced under these conditions. These results led to considerable improvement in the flow efficiency of oilwell completions. However, all of the reported tests have been made with a liquid in the test sample. In view of this. and the problems on gas-well completions, a series of tests on gas-saturated samples was started to determine if a significant difference exists in the results of perforating gas-bearing formations as compared to oil-bearing formations. Laboratory Procedures and ResultsThe objectives of these tests were to determine the relative effects of pressure conditions and fluid conditions in the wellbore at the time of perforation of gas-saturated samples in comparison to the previous work done on oil-saturated samples. JPT P. 647ˆ

A Practical Approach to Gas Deliverability Predictions with the Use of an Electronic Digital Computer

Abstract This paper presents a method of estimating the physical deliverability ofgas at the wellhead from depletion-type gas reservoirs, prior and subsequent tothe years of declining production. A prediction programme suitable for amedium-sized digital computer is given. It utilizes measured wellhead pressuredeliverability and absolute open flow potential curves for a field-averagewell. The predictions show the length of time a field is capable of deliveringa specified constant daily volume of gas. In addition, for each predictionperiod, the average reservoir and wellhead pressures, the average maximumproduction capacity, the QMax as determined by the Alberta Oil and GasConservation Board formula, and the cumulative gas volumes produced arecalculated. The programme also takes into account field compression and/or thedrilling of additional wells when required. Introduction Reliable gas deliverability predictions are essential for economic forecastsof gas field performance. The calculation basically involves an adaption of thefamiliar equation in U.S.B.M. Monograph7, relating flow rate toreservoir pressure. The equation only indicates a well's capacity to producegas at the reservoir sand-face. In actual practice, it is desirable to know thegas volumes a well is capable of delivering against a back pressure oftransmission lines, processing plants and field gathering lines. When the openflow equation is used for pipeline or wellhead deliverability calculations, itis necessary to calculate a relationship of Q versus flowing sand-facepressures for a constant-flowing wellhead pressure. As wellhead pressures areusually measured during back-pressure tests, these are used directly inplotting a wellhead deliverability curve, as described by Crawford (1). For maximum reliability, the predictions for any field frequently must berevised as additional information and production history become available. Toperform the calculations by hand is an arduous task requiring considerable timespent on routine work. A medium-sized electronic computer is ideally suited forthis application, and, after the programme is written, long-rangedeliverability forecasts at various rates may be made in a matter ofminutes.

Recent Developments in the Interpretation and Application of DST Data

Abstract This paper presents a summary of the latest drill-stem test interpretation techniques which may be applied by well operators to the majority of field cases. Recommendations are submitted for obtaining better DST data, and the evaluation of data received is discussed. Oil, gas and multiphase flow are considered. Methods of calculation are advanced to help determine reservoir pressure, productivity index, transmissibility, damage ratio, radius of investigation and absolute open-flow potential. Application of calculated information to well completion is discussed, and several gas case histories are tabulated which illustrate the general correlation between DST information and actual well performance. Introduction The information contained with a drill-stem test report may be considered to be of four general categories:factual data including statistical well information and a description of the testing tools;measured data concerning the recovered fluids and their properties, the time periods involved and general remarks based on observations during the test;recorded pressure and temperature data; andinterpretation calculations, where applicable. Greater emphasis is now being placed on the quality and completeness of the physical measurements and observations made during the test. This has been necessary in order to complement the accuracy and dependability of the pressure-recording instruments. Interpretation is considered an important part of the drill-stem test, and for this reason the necessary calculations are now being done on the majority of tests run in Canada. This information has proven to be of considerable assistance to the well owner in well-completion. formation-evaluation and hydrodynamic studies. This paper is an up-to-date presentation of practical methods of drillstem test interpretation and suggestions for improved testing techniques generally applicable to Canadian conditions. Previous authors' interpretation methods are combined with new developments and modifications to present a comprehensive interpretation guide for the great majority of DST results encountered. Evaluation of Basic DST Data Before he can begin the drill-stem test interpretation, the well operator must evaluate the basic data which were measured and recorded. Examination of the pressure data and the charts will reveal whether or not the test was satisfactory from a mechanical viewpoint and will help to verify the accuracy of the gauges. A zero-pressure base line is drawn on the chart by the bourdon tube pressure-recording instrument prior to assembly in the testing string, and the recorded pressure must "zero-in" on this base line at the time of tool assembly and "zero-out" during disassembly after the test. Since stair-stepping pressure curves may be caused by gauge malfunction, they must be considered to be unrepresentative of true formation pressures. Depending upon the severity of the steps, such pressure data may be of some value but must be used with extreme caution. If all gauges appear to have recorded correctly, the proper way to check their accuracy is to compare their recorded pressures at such key points as initial closed-in pressure, final flow pressure and final closed-in pressure. If the initial and final hydrostatic pressures are clearly defined on the charts, these may be used as well. The recorded pressure difference between any two gauges at these key points is compared with the predicted difference due to the hydrostatic head between the gauges. The discrepancy between the recorded and calculated difference is divided by two, and this quantity is calculated as a percentage of the average pressure of the two gauges. This is equal to the possible per cant error of each gauge, assuming their accuracies to be equal. The volumes of liquid recoveries often are difficult to determine accurately due to intermingling of the various fluids produced and, occasionally, due to severe gas-cutting. Gas flow measurements may be hampered by liquid flow through the flare line. JPT P. 1213^