Static Bottomhole Pressure Research Articles

Interpretation of Neural Network Models – New Insights of Estimating Static Bottom-Hole Pressures of Gas Wells in Nigerian Petroleum Provinces

Methods to determine static bottom-hole pressure (BHP) from surface measurements include the average temperature and z-factor method, the Sukkar-Cornell method, the Cullender-Smith method, and the Poettmann method. Among these methods, the Poettmann method is preferable in the petroleum industry but with a concern for software developers, as the integral values to determine the static BHP are tabular. In this study, neural network-based models to predict the integral values using pseudo-reduced pressures and temperatures were developed. The 2-3-1, 2-4-1, and 2-5-1 neural-based models had overall correlation coefficients (R) of 0.9974, 0.99835, and 0.99745, respectively, for the maximum-minimum normalization method and R of 0.99745, 0.99805, and 0.9992 for the clip-scaling method. Comparing the models' predictions with the Lagrangian interpolated values resulted in R of 0.99895 and 0.9995 for the maximum-minimum and clip-scaling-based models. Thus, the developed models can predict Poettmann's integral values without table look-up to estimate static BHP in gas wells.

HYDRODYNAMIC STUDIES OF WELL 32 OF THE SOUTHERN SECTION IN THE CHINAREVSKOYE FIELD OF THE WEST KAZAKHSTAN REGION

The paper analyzes the factors influencing the development of high-quality and cost-effective oil and gas reserves in the region (assessment, design). In order to operate wells, directions for calculating the size of reserves have been found. The scientific and technical trends of their (wells) development are considered. A comprehensive analysis of complex surveys was carried out at well No32 of the Chinarevskoye oil and gas condensate field, located in the southern section of the region. Hydrodynamic studies were carried out by interpreting the pressure recovery curve (PRC) to determine reservoir pressure, reservoir properties and the state of the bottomhole zone. These studies confirmed the low porosity properties of the reservoir: permeability - 0.004 mkm2 , conductivity - 0.056 mkm2 *m, hydraulic conductivity - 0.055 mkm2 *m/MPa*s. The skin factor varied in the range from - 0.92 to 18.4, which indicates a deterioration in the state of the bottomhole formation zone. Reservoir pressure dynamics (reduced to WOC) according to hydrodynamic studies showed that in the deposit, as the reservoir is withdrawn, there is a decrease in reservoir pressure. As of October 2019, according to the pressure build-up data, the formation pressure in well 32 (at the VNK level) is 38 MPa. Well 32 during the analyzed period (5 months) worked in three modes (from July to September 2019 with a washer with a diameter of 6 mm, from the end of September with a washer with a diameter of 8 mm, in October - 10 mm). At the same time, with an increase in the washer diameter to 8 and 10 mm, the downhole working pressure sharply decreased from 25 to 11 MPa and the static bottomhole pressure from 37.5 to 29.7 MPa. During the analyzed period, the well worked with a bottomhole pressure below the saturation pressure of oil with gas. The average gas-oil ratio was 757 m3/m3.

Assessing hydrocarbon prospects in Abu Madi formation using well logging data in El-Qara field, Nile Delta Basin, Egypt

In this work, the petrophysical properties of Abu Madi reservoir in El-Qara Field at northern Nile Delta Basin (NDB) were evaluated depending on well logging data of two wells: El-Qara-2 and El-Qara-3. This evaluation revealed that in El-Qara-2 well, the promising gas zone is detected between depths of 3315 and 3358 m, while in El-Qara-3 well, the best gas interval is detected between depths of 3358 and 3371 m. In addition to the production test parameters (gas rate, condensate rate, gas gravity, condensate gravity, gas-to-oil ratio, flowing tubing head pressure, flowing bottom hole pressure, and static bottom hole pressure), the calculated petrophysical parameters (shale volume, total porosity, effective porosity, and water saturation) for both intervals were relatively similar. This confirms that the investigated wells were drilled at the same reservoir interval within Abu Madi Fm. The depth variation in the examined zones was attributed to the presence of buried normal faults between El-Qara-2 and El-Qara-3 wells. This observation may be supported from the tectonic influence during the deposition of Abu Madi Fm. as a portion of the Messinian syn-rift megasequence beneath the NDB.

Evaluation of Heavy Paraffin Solvent Injection in Langgak Oil Field

LGK 14 and LGK 25 wells are oil production wells with high paraffin levels. The presence of paraffin around well perforation causes many problems. One of which is a decrease in the rate of production. It solved with rig less workover / well service (WO/WS) is an injection of heavy paraffin solvent. LGK 14 well uses sucker rod pump and LGK 25 uses an electrical submersible pump. Main steps in LGK 14 are injecting heavy parasol, soaking, displacing and producing. The other wells have differences where before the heavy parasol injecting, pump washed first. The challenges are high static bottom hole pressure (SBHP) and fluid reactions. The results show for LGK 14 well decreased oil rate from 25 BOPD to 21.77 BOPD after the heavy parasol injection. LGK 25 well increased the production rate from 21 BOPD to 29.99 BOPD.

Estimating the Static Bottom-Hole Pressure of Gas Wells by Top Node Calculation Using Apparent Molecular Weight Profiling

A reservoir’s static bottom-hole pressures (SBHPs) are an integral component of many reservoir evaluation disciplines. The SBHP is normally acquired through gauge measurements; however, this method has disadvantages such as cost and risk. Accordingly, the ability to accurately estimate the SBHP would provide a cost-effective and safe alternative to well intervention. In this work, a new calculation method is introduced to predict the SBHP of a natural gas well. This method differs from existing methods by utilizing the apparent molecular weight profiling concept. Based on the inputs of pressure and temperature gradient data, an iterative calculation scheme is applied to produce a well-specific molecular weight profile. This profile is used along with a modified form of the equation of state to perform top node pressure calculations and ultimately predict the SBHP for gas wells. The top node method was tested rigorously using 75 case studies from five different fields and reservoirs and the prediction results were compared with actual field measurements. Also, the prediction performance of the top node method was compared with those of four previous methods (Rawlins and Schellhardt, Rzasa and Katz, Sukkar and Cornell, and Cullender and Smith). The results of this work showed that the top node calculation method was accurate in predicting the SBHP and has outperformed the four previous methods.

Importance of Drilling Fluids' Rheological and Volumetric Characterization to Plan and Optimize Managed Pressure Drilling Operations

Abstract Managed Pressure Drilling (MPD) is an alternative to overbalanced and underbalanced drilling in conditions where pore pressures and fracture gradients are so close to each other (depleted reservoirs, deep and ultra-deep offshore reservoirs) that it is not possible to drill significant depths without setting a casing. While MPD enables an operator to drill longer footages without setting a casing, it requires precise estimation of equivalent circulating density (ECD) during drilling and static bottomhole pressure (SBHP) during non-drilling times. General practice in the drilling industry is to use rheological and volumetric properties of drilling fluids measured at surface to estimate ECD and SBHP. Consequently, ECD and SBHP measured using MWD and LWD tools in the field do not match the theoretical calculations. This study shows the importance of introducing the effect of downhole conditions to hydraulic equations in order to estimate ECD's and SBHP's accurately. Paraffin-based synthetic drilling fluid is used for this purpose. The effect of pressure and temperature on density of fluid is determined using PVT cell experiments. An equation relating the density of the fluid to pressure and temperature is determined using linear and non-linear regression techniques. Rheological characterization of the fluid was obtained on a Fann 75 HPHT rotational viscometer. A Bingham plastic model was used to define shear stress - shear rate relation of the fluid in all pressures and temperatures. The effect of pressure and temperature on plastic viscosity and yield point are determined using linear and non-linear regression techniques, similar to the ones used in PVT analysis. Both onshore and offshore cases are investigated and the effect of incorporating downhole effects to density and rheological parameters on ECD are analyzed. Introduction As a result of the depletion of most of the known reservoirs around the globe, companies are searching for oil and gas in more challenging areas such as deep and ultra-deep offshore locations. In addition, high oil prices motivate the industry to produce the last measure of oil from mature oil fields where the pressure is depleted. The conventional overbalanced drilling technique creates a major drawback to drilling in ultra-deep and depleted reservoirs. In ultra-deep offshore locations, pore pressure and fracture pressure gradients are very close to each other, and with conventional drilling, it is hard (sometimes impossible) to drill a hole up to the target depth(1). In the case of depleted reservoirs, pore pressure is so low that it is not possible to drill without damaging the formation. These challenges create the need for a new technology to drill in such hostile environments. Managed Pressure Drilling allows drilling of longer intervals by drilling overbalanced while maintaining near constant bottomhole pressure, using a combination of drilling fluid density, equivalent circulating density (ECD) and casing back pressure in a closed system(2, 3). While MPD will enable operators to drill longer sections and use light drilling fluids, it does require better wellbore pressure management. Only by managing the wellbore pressure, will it be possible to decide on which type of drilling fluid to use and how deep it can be used.

On the Calculation of Static Bottom-Hole Pressures in Gas Wells

In “Static Bottom-Hole Pressure in Wells” (Petroleum Science and Technology, 2006, 24:113–116), Hashim and Makola present a method for the calculation of static pressure gradients in vertical wells. In the present discussion, the methodology proposed by Hashim and Makola is examined and alternate guidelines for the calculation of static pressure gradients are provided. In particular, this work examines their proposed mathematical simplifications and practices that could compromise the accuracy of the calculations. References to recommended practices and procedures for calculating static bottom-hole pressure in gas wells are also presented.

Effect of P– ρ– T behavior of muds on loss/gain during high-temperature deep-well drilling

High-pressure and high-temperature deep-well drilling is associated with several unusual problems. A recent report on one such well in the North Sea indicated an apparent partial mud loss during circulation and a pit gain after stopping the circulation. When the well was shut-in on gain, a pressure buildup was observed at the surface. In the present study, an attempt is made to explain these observations quantitatively with the help of pressure–density–temperature ( P– ρ– T) behavior of mud and the temperature changes in a static mud column. An analytical method is developed to estimate the maximum pit gain when the linear temperature profile of wellbore changes from that immediately after circulation to geothermal. To estimate the maximum rise in pressure if the well is shut-in during these temperature changes, an analytical method is outlined. An approximate relationship between the gain and lapsed time after circulation is proposed. Estimated maximum gains for an example well are of the order of a few tens of barrels for both water- and oil-based muds. In general, estimated maximum gains in the case of oil-based muds are nearly twice that for water-based muds of identical densities. It is also shown that the maximum rise in surface pressure under shut-in condition which is of the order of a fraction of one ppg, is approximately equivalent to the decrease in static bottomhole pressure under open condition.

Electric Submersible Pump Application and Operation in Small Openhole Completions

Summary Amoco Production Co. has operated electric submersible pumps (ESP's) in 4 3/4 -in. (12.1-cm) open holes in the Grayburg formation of its Midland Farms Unit, Andrews Dist., since 1977. The Midland Farms (Grayburg) reservoir is a low-pressure [400- to 600-psi (2.8- to 4.1 -MPa) static bottomhole pressure (BHP)], high-PI (ranging from one to seven) formation that requires artificial lift drawdown to 70-psi (4.8 × 10 -Pa) BHP for maximum oil recovery in a high-water-cut production (89%). The 28 ESP's operating in small open holes (1979) comprise 10% of the producing wells (270 total producers) in the unit, yet they generate 34% [2,340 B/D (372 m /d)] of the field's total oil production. Through Dec. 1979, ESP's have been credited with 850 B/D (135.1 m /d) in incremental production, and secondary reserves have been increased by approximately 4% [2 million bbl (317 975 m )], or 71,400 bbl (11 352 m ) per installation. Pulling and repair costs for the ESP wells are $0.04/bbl fluid lifted less than for artificially lifted (beam lift) wells. Introduction This study was completed in 1980 with data taken through Dec. 1979 (Table 1). In July 1982 there were 84 ESP's operating in 4 3/4 -in. (12.1 -cm) open hole completions in the unit. This is 31 % of the producing wells in the unit. These wells produce 5.055 B/D (803.7 m /d) oil, which is 52% of the unit's production. There have been two additional wells plugged and abandoned because of ESP's that stuck and were unretrievable since this paper was written. The study has not been updated to include any additional performance data other than those presented here. These installations are still performing satisfactorily and resulting in optimized pumping conditions. During primary recovery, the unit wells were produced by flowing under reservoir pressure and later by artificial lift. Water cuts reached 65% during primary recovery, with water being disposed in the aquifer and later in the oil column [4.800 ft (1.463 km)] in peripheral wells. A secondary recovery pilot began in 1971. When water cuts exceeded 85 %, it became apparent that beam lift, limited by 4 3/4 -in. (12.1 -cm) open hole completions, could not match lift capacity with production capability. ESP's have been used in this reservoir since 1977. While beam-unit capacity is 650 B/D (103.3 m /d) fluid, ESP's have produced 600 to 1,700 B/D (95.4 to 270.3 m /d) per installation with a producing BHP of 70 psi (0.5 MPa). ESP's have reduced operating costs and increased secondary reserves. The small open hole, while limiting beam-lift capacity, has had little effect on ESP applications. There are currently 33 ESP's in operation (1979), 28 of which are set in the 4 3/4-in. (12.1-cm) open holes. Operations have been successful and only one ESP lost downhole because of hole size limitation. Currently, 40% of the total produced fluid of 6,910 B/D (1099 m /d) oil and 56,400 B/D (8967 m /d) water is lifted by ESP's. Assumptions and Qualifications 1. This study is based on data taken from ESP's and beam units installed in Amoco Production Co.'s Midland Farms Unit, Andrews County, TX.2. Several pumps from different vendors were evaluated. JPT P. 1719^

Analyzing Well Performance X

Abstract After a general discussion of fluid flow, this paper reviews the data which are necessary for well analysis. The acoustic liquid level instrument is described, well producing rate efficiency (with and without gas) is discussed and an analysis of downhole equipment is given. Introduction Analyzing well performance is an important step toward increasing profits by improving production techniques. The analysis is made by field tests and examination of well data. The acoustic liquid level instrument offers valuable information, because downhole pressures can be determined from the depth-to-liquid measurement. Fluid Flow (generalized) Fluid flow in a reservoir is caused by movement of fluid from a high-pressure area to a low-pressure area. Fluid flow into a wellbore occurs when fluids, present in the wellbore are removed so that the pressure is decreased. Then? fluid from an area of higher pressure flows into the lower-pressure wellbore (Fig. 1). Fluid flow into a wellbore is approximately proportional to the drawdown pressure, which is the difference in pressure between the higher pressure reservoir and the low-pressure wellbore. The greater the difference, the greater the fluid flow. Figure 2 represents some ideal cases of fluid flow in a reservoir. The lower the wellbore pressure the greater the inflow rate. Generally, in the past, the inflow rate has been assumed to be proportional to the drawdown pressure. This procedure is still used in wells which produce liquid without gas. Vogel(I) presents a curve for predicting flow rates in 2-phase flow (liquid and gas). This curve is shown on the Well Analysis sheet and should be used when predicting flow behaviour in wells making liquid and gas. Necessary Data for Well Analysis Four factors are extremely important in analyzing well performance:static bottom-hole pressure (or reservoir pressure),producing bottom-hole pressure,well test andpump capacity. For maximum withdrawal, the producing bottom-hole pressure must be low compared to the static bottom-hole pressure. A producing bottom-hole pressure of 75 psi is low compared to a static reservoir of 2300 psi, and practically all of the production is beng obtained. However, if the static reservoir pressure is 100 psi, approximately one-fourth of the production is being obtained. The well test must also be known. If the producing wellbore pressure is low compared to the static reservoir pressure, maximum inflow is occurring. However, if the maximum inflow is less than commercial production, action must be taken. Last, the pump capacity must be known. If the pump capacity is not matched suitably to the well's production, excessive wear and a mechanical loss of efficiency are occurring if the pump capacity greatly exceeds the production rate. A production loss occurs if the, pump capacity is less than the well's producing capacity. Note the importance of each item, by trying to determine the proper action on each of the wells in Table 1 when only one of the four items on each well is omitted.

Calculation of Bottom-Hole Pressures For Deep, Hot, Sour Gas Wells

A somewhat neglected method of calculating bottom-hole pressures, that of Sukkar and Cornell, does not involve trial and error and is very fast for hand calculation; but it does not allow for the severe conditions of modern gas wells. Here the method is refined to extend the pressures and temperatures, to allow for sour gas, and to make results readily accessible for hand calculation. Introduction Modem trends in gas well drilling have been toward deep, hot, high-pressure completions. Currently, gas wells are being drilled to depths of about 25,000 ft in the southwestern U. S. As would be expected, bottom-hole pressures for these wells are high (about 16,000 psi), and bottom-hole temperatures are in excess of 400 deg. F. The gas produced from many of these deep wells is sour. To run bottom-hole pressure bombs is costly. and because the sour gas rapidly corrodes wirelines it may also be disastrous.There is often no indication of liquid in these wells, so it is possible to compute bottom-hole pressures from measured wellhead data. Of the many methods of computing bottom-hole pressure, perhaps the best known are - the method for static and flowing gas columns outlined in the State of Texas backpressure manual, and - the static and flowing gas column method described by Cullender and Smith. The static method described in Ref. 1 is the Rzasa and Katz Method II, related to the older Rawlins and Schellhardt method. The flowing method in Ref. 1 is a modification of the static column method, which is based on estimating flowing friction from the Weymouth gas flow equation. Although the static method in Ref. 1 can be used with several depth increments to provide reasonable answers for deep wells, the flowing method is not recommended for deep, high-rate wells. The Cullender and Smith method is based upon a mechanical energy balance and is generally reliable for both static and flowing gas columns. But methods in both Ref. 1 and Ref. 2 involve tedious trial-and-error solutions. The Cullender and Smith method is best solved by computer if many determinations are required. There is a method that does not involve trial and error, however, that is very fast for hand calculations; but surprisingly, this method has received very little attention and use. This paper is based on that technique.A method presented by Fowler, involves integrated values of the gas law deviation factor, Z, with pressure, and is a direct method of calculating static pressure, and is a direct method of calculating static bottom-hole pressure, assuming a constant average temperature. Sukkar and Cornell extended Fowler's analysis and presented a general approach to calculating both static and flowing bottom-hole pressures for pure natural gas. They derived a pressure integral for perfectly vertical pipe by assuming negligible kinetic energy change, steady-state isothermal flow, and no work done by the gas in flow. Sukkar and Cornell evaluated the integral generally in terms of pseudoreduced pressures. The integral contains the pseudoreduced pressures. The integral contains the gas law deviation factor as a function of pressure, but it is assumed that temperature can be treated as an average over the depth range of interest. This is not an important weakness in the method because a depth of interest can be broken into several intervals to provide accuracy. The integral is based on a mechanical provide accuracy. The integral is based on a mechanical energy balance for a flowing column and is essentially identical with the Cullender and Smith result. JPT P. 85

The Calculation of Pressure Drop in the Flow of Natural Gas Through Pipe

Abstract An equation has been derived for use in calculating the sandface pressure of flowing gas wells in which the variation of the compressibility factor of the gas with pressure is taken into consideration. This variation due to compressibility has been put into both graphical and tabular form. Comparison of calculated results with field measured results were made on 20 dry gas wells from a given field and 11 distillate wells from different fields. The agreement between calculated and observed results is good. In addition to their use in the calculation of sand face pressures of flowing wells, the factors can be used in the direct calculation of the static bottom hole pressure of gas wells, the capacity of gas transmission lines, and in the calculation of the theoretical isothermal horsepower necessary to compress a natural gas. Examples demonstrating the use of various equations are given. Introduction Many of the equations used to calculate the sand face pressures of flowing gas wells from well head data do not take into consideration rigorously the deviation of the natural gas from ideal gas behavior. For low pressure wells this error is not serious. For high pressure wells flowing at high rates this error can be serious. Sandface pressures are used to determine the producing capacity of gas wells as shown in the U. S. Bureau of Mines Monograph 7. An equation has been derived for use in calculating the sand face pressure of flowing gas wells in which the variation of compressibility of the gas with pressure is taken into consideration. This variation due to compressibility has been put into both graphical and tabular form. In addition to their use in the calculation of sandface pressures, these "factors" can also be used to give a direct solution in the calculation of the static bottom hole pressure of gas wells, the calculation of the capacity of gas transmission lines, and the calculation of the isothermal horsepower necessary to compress a gas.