Methodology of production log interpretation. interpretation. The methodology of PL analysis is the essentially same from one interpretation package to the other (with the exception exception of statistical statistical analysis analysis packages packages). ). The interpretation interpretation packages packages are howeve howeverr much much more rigorous to generate a more accurate analysis and allow the interpreter to spend more time on analysis and less time on manipulating the data.
PL analysis in single phase flow By single phase flow we mean a single fluid type – oil, gas or water. Because there is only one fluid type there is no slip velocity. 1) Make Make a cross crossplo plott of spinn spinner er res respon ponse se vs line line spe speed ed to to gene generate rate the the spin spinner ner calibra calibration tion.. 2) Appl Apply y the the spin spinne nerr calibr calibrati ation on to log log spin spinne nerr and line line spee speed d data data to get appar apparen entt fluid fluid vel veloc ocit ity y for for each zone. 3) Corr Correct ect the the appar apparen entt flui fluid d velo veloci city ty to aver averag agee flu fluid id velo velocit city. y. 4) Calc Calcula ulate te dow downh nhol olee flow flowra rate tess usi using ng casi casing ng / tub tubing ing inter internal nal dia diame mete ter. r. 5) Conv Convert ert fro from m down downhol holee units units to surf surface ace unit unitss using using PVT PVT data data allow allowing ing for for gas gas bein being g relea released sed from from solution (if relevant). 6) Pre Present sent the the res resul ults ts in a way way mean meanin ing gful ful to to the the clie client nt..
PL analysis in 2 phase flow By two phase flow we mean two fluid types which can be gas/oil, gas/water or oil/water. Conventional multi-phase production log interpretation follows the same generic pattern however we have to consider phase holdup’s (fractional occupancy of the phases) and slip velocities (due to gravity less dense fluids will travel up the well at a faster speed than heavier fluids). 1) Make Make a crossplo crossplott of spinner spinner response response vs line speed speed to generate generate the spinner spinner calibration. calibration. 2) Apply Apply the spinner spinner calibration calibration to log spinner spinner and line speed data to get apparent apparent fluid velocity velocity for each each zone. 3) Correct Correct the apparent apparent fluid veloc velocity ity to average average fluid fluid velocity velocity.. 4) Generate Generate PVT data for downh downhole ole fluids fluids or read read end points points of of log. log. 5) Generate Generate the downhol downholee holdup holdup profile profile using using fluid fluid ID tools tools.. 6) Determine Determine phase phase slip slip velocitie velocitiess from charts charts or or correlations correlations.. 7) Calculate Calculate downhole downhole phase phase superficial superficial velocities velocities using using holdup holdup and slip slip velocity. velocity. 8) Convert Convert downhol downholee superficial superficial phase velociti velocities es to downhole downhole barrels per day. day. 9) Convert Convert from downhole downhole units units to surface units units using PVT PVT data allowing for gas gas being released released from solution (if relevant). 10) Convert from downhole downhole barrels per day to surface units using PVT PVT data. 11) Present the results in a way meaningful to the client.
PL analysis in 3 phase flow In three phase flow oil, gas and water are flowing at the same time. For three phase flow it is necessary to have two fluid identification tools. Typically the 2 fluid identification tools we use are capacitance water holdup to determine the water holdup together with density to determine determine the remaining remain ing oil and gas holdups. The The water holdup can be read directly off a chart of fractional fracti onal response vs holdup for the capacitance tool. Alternatively the Gas Holdup Tool can
be used to determine gas holdup which can then be used with density density to determine the remaining water and oil holdups. The problem with the capacitance tool is that it is ideally a water / hydrocarbon tool but that it has different end points for oil and gas. This means that the user must make an estimate of the hydrocarbon end point somewhere somewhere between the gas and oil frequency which is itself dependent upon the gas / oil ratio which is not known.. Methodology Methodology of conventional conventional 3 phase production log interpretation. interpretation.
1) Make Make a crossplo crossplott of spinner spinner response response vs line speed speed to generate generate the spinner spinner calibration. calibration. 2) Apply Apply the spinner spinner calibration calibration to log spinner spinner and line speed data to get apparent apparent fluid velocity velocity for each each zone. 3) Correct Correct the apparent apparent fluid veloc velocity ity to average average fluid fluid velocity velocity.. 4) Gener Generate ate PVT PVT data for dow downho nhole le fluids fluids.. 5) Generate Generate the downhol downholee holdup holdup profile profile using using fluid fluid ID tools tools:: a) Determine the water holdup directly by reference to a fractional response ve holdup chart for the capacitance tool. b) Having calculated the water holdup, calculate the oil and gas holdups. 6) Determine Determine phase phase slip slip velocitie velocitiess from charts charts or or correlations correlations.. 7) Calculate Calculate downhole downhole phase superficial superficial velocities velocities using using holdups holdups and slip velocity velocity.. 8) Convert Convert downhol downholee superficial superficial phase velociti velocities es to downhole downhole barrels per day. day. 9) Convert Convert from from downhole downhole barrels barrels per day to surface surface units units using using PVT PVT data. 10) Present the results in a way meaningful to the client. As an alternative to using the capacitance and density tools for 3 phase analysis it is possible to use the gas holdup and density tools. In this event step 5) would be: 5) Generate Generate the downhol downholee holdup holdup profile profile using using fluid fluid ID tools tools:: a) Determine the gas holdup using the gas holdup tool. b) Having calculated the gas holdup, calculate the oil and water holdups. Calculation of water holdup from the capacitance tool: The first step is to determine the fractional tool response (the tool response is normalised because each tool has slightly different end points). End points for hydrocarbon and water may be read off the shut in log. Fractional response is the calculated from: Fr = (freq meas – freq oil) / (freq water – freq oil) The measured frequency is the tool frequency during flow. For example freq water = 1360 cps, freq oil = 3850 cps. Tool Tool reading when logging logging = 1550 cps. Fractional response = (1550-3850)/(3850-1360) = 0.924.
Referring to the (somewhat idealised) chart below: SONDEX FLUID CAPACITANCE TOOL FRACTIONAL TOOL RESPONSE vs HOLD 1.2
1
E S N O0.8 P S E R L O0.6 O T L A N 0.4 O I T C A R F0.2
0 0
0.2
0 .4
0 .6
0.8
1
1.2
WATER HOLDU
A fractional response of 0.924 corresponds corresponds to a water holdup of 0.78. 0.78. Water holdup, Yw = 0.78 Calculation of water holdup, oil holdup and gas holdup (using Capacitance and Density tools): Having established water holdup, Yw, oil and gas holdups are determined by using density data. The downhole densities of all 3 phases must be known. known. Water Holdup, Yw = Measured directly from Capacit ance Water Holdup tool using Freq. / Yw chart. Oil holdup, Yo = ((dens meas – dens gas) + Yw (dens gas – dens water)) / (dens oil – dens gas) Gas holdup, Yg = 1 – Yw – Yo or: Gas holdup, Yg = ((dens oil – dens meas) + Yw (dens water – dens oil)) / (dens oil – dens gas) Calculation of gas holdup, oil holdup and water holdup (using Gas Holdup and Density tools): If the well pressure is below about 3000 psi the changes with changing oil/water ratio on the gas holdup tool can be assumed to be within the error of the final result. Having established gas holdup, Yg, oil and water holdups are determined by using density data. The downhole densities of all 3 phases must be known. Gas Holdup, Yg = Measured directly from Gas Holdup tool using correction algorithm. Oil holdup, Yo = ((dens meas. – dens water) + Yg (dens water – dens gas)) / (dens oil – dens water) Water holdup, Yw = 1 – Yg – Yo
Slip Velocity to use in 3 phase flow:
Slip velocities for 3 phase flow are not well defined. Basically there are two slip velocity models: When oil and gas occupy the smallest holdup they are combined and an equal slip velocity for gas plus oil is used. When When oil and water occupy the smallest holdup they are combined and set to zero and slip velocity gas for is used. When holdups for oil, gas and water are known they are combined with total fluid velocity and slip velocities to generate superficial velocities for each phase. The superficial velocities are then converted to downhole flowrate and then corrected to surface equivalent flowrate. Calculation of superficial velocities when water is the biggest biggest holdup: Yh = Water (Heavy) phase holdup. Yl = Oil phase holdup + Gas phase holdup. Both are assumed to have the same slip velocity, Vs. Vs. The following equations are used to calculate the superficial phase velocities: Qwater ft/min = (Yh x Qtotal ft/min) – (Yh x (1-Yh) x Vslip Vslip light ft/min) Ql ft/min = Qtotal ft/min – Qwater ft/min Ql ft/min = Qoil ft/min + Qgas ft/min Qoil ft/min = Yo / (Yo+Yg) * Ql ft/min Qgas ft/min = Qtotal ft/min – Qw ft/min – Qo ft/min Calculation of superficial velocities where gas is the biggest holdup: Yh = Water + Oil (Heavy) phase holdup. Both are assumed to have the same slip velocity, Vs. Yl = Gas phase holdup. The following equations are used to calculate the superficial phase velocities: Qoil+water ft/min = (Yh x Qtotal ft/min) – (Yh x (1-Yh) x Vslip Vslip light ft/min) Ql, gas ft/min = Qtotal ft/min – Q(oil+water) ft/min Qh ft/min = Qoil ft/min + Qwater ft/min Qoil ft/min = Yo / (Yo+Yw) * Qh ft/min Qwater ft/min = Qtotal ft/min – Qg ft/min – Qo ft/min
Equations Equat ions ( Two phase flow): flow ): Apparent Fluid Velocity, ft/min = ((RPS / Slope, rps/ft/min) + Threshold, ft/min) – Line Speed, ft/min Average Fluid Velocity = Apparent Fluid Velocity x Flow Profile Correction Factor (0.83 if not known) Calculation of phase holdup’s (Densities of both phases are downhole densities):
Heavy Holdup (Yh) = (Density meas. – density light phase) / (Density heavy phase – density light phase). Light Holdup (Yl) = 1 – Yh Slip velocity estimation:
Gas – Liquid Flow Correlation (Smolen) If Yh < 0.05 then the slip velocity of gas = 0 otherwise: Vslip gas = 60 (.95-Yg^2)^.5 + 1.5 Oil – Water Flow Correlation (Smolen) If Yw < 0.15 then the slip velocity of oil = 0 otherwise: Vslip oil = 39.4 (Dens water – Dens oil)^.25 exp((-0.788 exp((-0.788 Yo ln((1.85/(Dens water – Dens oil)) Correction to slip velocity for deviation:
Deviated Slip velocity = Vertical slip vel x (1 + deviation from vertical in degrees x 0.04) Calculation of superficial velocities:
Qh = Heavy phase superficial velocity, Ql = Light phase superficial velocity. Qh ft/min = (Yh x Qtotal ft/min) – (Yh x (Yl x Vslip light ft/min)) Ql ft/min = Qtotal ft/min – Qheavy ft/min Conversion from superficial velocity to downhole BPD:
BPD = ft/min x Internal Diameter Di ameter inches^2 x 1.4. Conversion to surface units using PVT data:
Oil Formation F ormation volume factor, Reservoir BBL / Standard BBL Oil solution GOR, G OR, Standard cu ft / Standard Sta ndard BBL BBL oil. Gas Formation F ormation volume factor, Reservoir BBL / MSCF. Oil: STBOPD = Downhole oil / Oil formation volume factor Water (if used): STB Water = Downhole water / water formation volume factor Gas: MSCFD MS CFD gas = (Downhole gas / Gas Ga s formation volume factor) + (STBOPD * (Oil Solution GOR/1000))
PRODUCTION LOGGING EXAMPLES TWO PHASE (OIL/GAS) PRODUCTION LOG FOR EXAMPLE ANALYSIS
0
150
-9
GAMMA -200
21 0 SPINNER
DENSIT
200
2800
200
245
LINE -200
1 3000 PRESSUR
LSP
255 TEMPERATUR
8150
8200
8250
DENSITY
8300
8350
8400
This log is the basis for our PLT interpretation by hand. The following text should be used in conjunction with spreadsheet PLINT PLINT oil-gas example.xls. example.xls.
Analysis of a 2 phase (gas and oil) Production log In this analysis, for familiarity, we will use imperial units. Starting with the illustrated production log above. Step 1: Calibration of the spinner response.
Spinner tools will have different responses due to the pitch of the impeller and to a certain extent the fluid that the mixture is in. The PLT job will have multiple up and down passes at different line speeds which are used to calibrate the spinner response. For this exercise, for simplicity we will determine the spinner response in the sump (which will give us the response slope and threshold) and assume that this response is valid for the rest of the zones. Referring to the log. In the sump from 8390-8410 ft we can read off the following values for line speed and spinner response. Line speeds are in ft/min (up is negative). Spinner response is in RPS. D1 is downward logging pass 1 etc. LSp LSpeed eed D1 37 RPS D1 2.1
LSp LSpeed eed D2 62 RPS D2 3.2
LSpe LSpeed ed D3 115 RPS D3 6.8
LSpe LSpeed ed D4 162 RPS D4 9.6
LSpe LSpeed ed U1 -27 RPSU1 -1.5
LSpee Speed d U2 -55 RPSU2 -2.8
LSpe LSpeed ed U3 -115 RPSU3 -6.6
LSp LSpeed eed U4 -152 RPSU4 -8.1
These values can then be plotted on a crossplot and a best fit (linear regression) line fitted. From the best fit line we can determine spinner response slope and the threshold. The crossplot of this data using CROSSPLO CROSSPLOT.XL T.XLS S is illustrated below.
Spinner Crossplo 12 y = 0.0614x 0.0614x - 0.348
10 8
S P R r e n n -200 i p S
6 4 2 Downw ard
0 -150
-100
-50
-2
Upw ard
0
50
-4 -6 y = 0.0547x + 0.022
-8 -10
Line Speed
10 0
150
20 0
Linear Linear (Upw ard) Linear Linear (Dow nw ard)
From this we get the slope of each line and the regression value when the line intercepts line speed zero. To get the intercept in ft/min at RPS zero we divide the line speed zero value by the slope. The resulting spinner spinner calibration calibrati on is: Threshold calculation
Lspd Zero
Intercept Down Intercept Up
Slope -0.3481 0.0229
Intercept Ft/min 0.0614 0.0547
5.7 - 0.4
We will use the downward spinner calibration. Slope = 0.614 RPS/Ft/min, Threshold = 5.7 ft/min. This apparent threshold is a little high however we do not know the condition of the bearings or the well fluid. Later we will refine it to generate zero fluid velocity in the sump. Step 2: Calculation of apparent fluid velocity velocity for each zone.
There are different methods to calculate apparent fluid velocity. The method we will will use is: Ft/min = ((RPS / Slope) + Threshold) Threshold) – Line Speed The threshold velocity is added to the total fluid velocity as it is the mixture velocity that the spinner cannot see due to it being below the threshold required to get the spinner rotating. Line speed is subtracted from the calculated total mixture mixture velocity velocity,, as it is a component component of the total. We want the flowrate flowrate at line speed zero. Reading off the log at depths above each perforation where flow is steady we can input the data into PLINT.XL PLINT.XLS. S. Below are the results using the above formula. Depth ft RKB 8175 8300 8400
Spinner RPS RPS 17.2 8.6 6.8
Line Speed ft/min 115 115 115
Slope rps/ft/min 0.0614 0.0614 0.0614
Threshold ft/min 5.7 5.7 5.7
Apparent Mixture Velocity ft/min 170.8 30.8 1.4
The sump calculation shows shows a fluid velocity of 1.4 ft/min. This is assumed to be zero in reality and may be the result in errors of our readings off the log. The fluid velocity for the sump is set to zero by adjusting the threshold velocity. This new threshold velocity is then applied to all the zones. In this case it does not affect the results much but in a very low fluid velocity well errors in threshold velocity can make a difference. Depth ft RKB 8175 8300 8400
Spinner RPS RPS 17.2 8.6 6.8
Line Speed ft/min 115 115 115
Slope rps/ft/min 0.0614 0.0614 0.0614
Threshold ft/min 4.3 4.3 4.3
Apparent Mixture Velocity ft/min 169.43 29.37 0.05
Step 3: Calculation of average average fluid velocity for each zone.
The fluid velocity the spinner is measuring is at its its centrali ralissed position in the flowstream. Looking at the diagram below we can see see a graph graphical ical repres represent entatio ation n of the fluid velocity flow profile across the wellbo llbore re.. The rela relati tio onshi nship p bet betwee ween meas measur ured ed (app (appare arent nt)) flui fluid d velo velocit city y and average fluid velocity is dependent on the degree of turbulence and the relationship of spin spinne nerr blade blade diam diamet eter er to well wellbo bore re diamet diameter. er. The The calcul calculatio ation n to corre correct ct for spinn pinner er blad bladee diame iamete terr is beyo eyond this this simplified analysis. Therefore we will use the industry industry accepted accepted relationship relationship where where aver averag agee velo veloci city ty is 0.83 of appar apparen entt velocity. In reality for turbulent flow this value can vary from about 0.75 to 0.95 0.95 and in laminar flow down to about 0.5. Laminar flow is not seen in multi-phase flow and only becomes becomes important at very low fluid velocities or in large diameter pipe. This is multi-phase flow so we will assume the flow profile is turbulent and use the generic correction factor of 0.83 (though for fullbore spinners in turbulent flow the correction factor is often approximately 0.9 and for continuous spinners approximately 0.75). 0.75). Thus: Average Fluid Velocity = Apparent Fluid Velocity x 0.83. Dept Depth h ft RKB 8175 8300 8400
Appa Appare rent nt Mixtu Mixture re Veloc elocity ity ft/min 169.4 29.4 0.0
Flow Flow prof profile ile corr correc ectio tion n factor 0.83 0.83 0.83
Aver Averag age e Fluid Fluid Velo Veloci city ty ft/min 140.63 24.37 0.04
Step 4: Generating PVT data to relate downhole conditions to surface conditions and vica versa.
The produced produced fluid properties properties we have are measured measured at surface surface conditions conditions.. The flowrates flowrates we measure measure at surface are also at surface conditions. However the responses we measure with our PLT tools are at downho downhole le condi conditio tions ns of elevate elevated d press pressure ure and temper temperatur ature. e. We use PVT PVT data (pres (pressu sure, re, volum volume, e, temper temperatur aturee relatio relationsh nships ips)) to relate relate surfa surface ce proper properties ties and flowra flowrates tes to down downhol holee and also also after after our our analysis to convert downhole properties and flowrates back to surface conditions. In ideal conditions the downhole fluid properties will be available from the client however most often they are measured during the shut in and generated from correlations. The downhole properties are dependent on the nature of the fluid and the downhole pressure and temperature. The properties required for analysis and where to obtain them from are: ar e: Survey temperature Survey pressure Surface Oil Flowrate Surface Gas Flowrate Surface Water Flowrate Oil API
From PLT log From PLT log Optional but very useful. Optional but very useful. Optional but very useful. From client
Oil formation volume factor From client or by correlation. Oil density downhole From client, from shut in log or by correlation. GOR at bubble point (Original GOR) From client or by correlation. Bubble Point Pressure From client or by correlation. Oil Oil solu soluti tion on GOR GOR at at surv survey ey pres presssure ure and and temp temper erat atur uree From From cli clien entt or by by cor corre rela lati tion on.. Gas Gravity From client % Nitrogen, H2S, CO2 From client Gas formation volume factor From client or by correlation. Z factor From client or by correlation. Gas Density downhole From cl client, fr from sh shut in in lo log (if flowing pressure is not very different from shut in pressure) or by correlati on. Water salinity From client Water formation volume factor From client or by correlation. Water density downhole From client, from shut in log or by correlation. Here is a very generalised summary of the changes in fluid properties from surface to downhole, but actual properties will depend on the fluid chemistry and downhole pressure and temperature: temperature: Oil has a larger volume downhole and a lower density than at surface due to elevated temperature and gas in solution. Depending upon the oil bubble point (pressure below which dissolved gas starts to come out of • solution) there will be gas liberated from the oil at wellbore flowing pressure. The greater the difference between the bubble point pressure and the wellbore flowing pressure the more gas comes out of solution and the less gas stays in solution. The gas that stays in solution is known known as solution GOR, Rs. • Water has a larger la rger volume downhole downhole and a lower density due to temperature. • The greater the salinity of the water the higher the density. density. Gas has a much lower volume downhole and a higher density than at surface due to elevated pressure. As pressure increases more gas will be dissolved in the oil and above the bubble point of the oil there will be no free gas. •
• •
•
Generating downhole properties is beyond the scope of this exercise. PL Interpretation manuals will have the correlations listed and software analysis packeages have them built in. There are many different types named after different researchers eg Standing’s correlations. correlations. For our interpretation we will use the following properties at survey flowing pressure pressure and temperature: Oil Formation volume factor Oil density Oil solution GOR Gas Formation volume factor Gas density
1.42 Reservoir BBL / Standard BBL 0.68 g/cc 666 standard cu ft / Standard BBL oil. 1.158 Reservoir BBL / MSCF. 0.13 g/cc
Gas formation formation volume volume factor is normally rcf/scf rcf/scf howeve howeverr in this example example it is in bbl / mscf. This This is because we are measuring downhole flow in barrels and we need continuity. To convert from reservoir cuft / standard cuft (rcf/scf) to bbl/mscfd: Bbl/mscf = (rcf/scf*1000)/5.615 Step 5: Generating Generating downhole holdup from PVT and fluid identification measurements.
Fluid identification tools include density and capacitance. In 2 phase flow (unless the density contrast between hydrocarbons and water is beyond the resolution of the density tool) it is best to use density as using capacitance requires reference to a holdup / response chart (and most likely other corrections). To calculate heavy phase (oil) and light phase (gas) holdups: Heavy Holdup (Yh) = (Density meas. – density light phase) / (Density heavy phase – density light phase). Light Holdup (Yl) = 1 – Yh The measured density values have been read off the log. Depth
Measur sured Density ity
ft RKB 8175 8300 8350
g/cc 0.465 0.635
Density sity Oil downhole g/cc 0.680 0.680 0.680
Density Gas downhole g/cc 0.130 0.130 0.130
Heavy Holdup Yh 0.609 0.918 0.000
Light Holdup Yl 0.391 0.082 1.000
Step 6: Determining slip velocity from correlations.
Slip velocity is the relative velocity of the light phase to the heavy phase. For example if we had a standing column of water with gas bubbling up through it, the velocity that the gas is bubbling up through the water is the gas slip velocity. There are various correlations for slip velocity and usually during computer aided analysis the user has the option option to use the correlation correlation which best fits the data. There There are also various various charts which can be used to derive slip velocities. In reality given the complexities of true flow slip velocities cannot be calculated exactly and the interpreter may need to edit slip velocities to make the interpretation make sense. We will use the following equations: equations: Gas – Liquid Flow In this case Yl = Y gas and Yh = Y water or oil. If Yh < 0.05 then the slip velocity of gas = 0 otherwise: Vslip gas = 60 (.95-Yg^2)^.5 + 1.5 – From Smolen (NB: Halliburton use Vslip gas = 65 (1-Yg)^.5 + 1.5) Oil – Water Flow In this case Yl = Y oil and Yh = Y water. If Yw < 0.15 then the slip velocity of oil = 0 otherwise: Vslip oil = 39.4 (Dens water – Dens oil)^.25 exp((-0.788 Yo ln((1.85/(Dens water – Dens oil)) – From Smolen (NB: Halliburton use a multiplier of 49.1 instead of 39.4)
Using the gas – liquid equation, oil and gas densities and downhole density measurements: measurements: at 8175 ft Yh is 0.61 and the slip velocity is 52.2 ft/min. At 8300 ft Yh is 0.92 and the slip velocity is 63.8 ft/min. In deviated wells up to 45 degrees deviation the slip velocity increases and above 45 degrees it starts to decrease. A correlation for this is: Deviated Slip velocity = Vertical slip vel x (1 + deviation in degrees x 0.04) In our analysis the well deviation is zero so we do not have to modify our slip velocity. Depth
Gas-Liquid Correlation ft/min 56.7 61.3 0.0
ft RKB 8175 8300 8350
Gas-Liquid Gas-Liquid Correlation ft/min (deviated well) 56.7 61.3 0.0
Step 7: Calculating downhole superficial phase velocities from average flowrate, holdup and slip velocity.
It is assumed that the spinner measures the total of total of the heavy and light flowrates including the light phase flow added contribution due to slip velocity. The superficial velocity is the velocity of the phase if it were to occupy the whole of the pipe. It is not the true velocity of that phase. Qh = Heavy phase superficial velocity. Ql = Light phase superficial velocity. The following equations are used to calculate the superficial phase velocities: Qh ft/min = (Yh x Qtotal ft/min) – (Yh x (Yl x Vslip light ft/min)) Ql ft/min = Qtotal ft/min – Qheavy ft/min For this case Yh is the oil holdup and Vslip is the gas slip velocity. Depth ft RKB 8175 8300 8350
Qt ft/min 140.63 24.37 0.04
Vs ft/min 56.7 61.3 0.0
Heavy Holdup Yh 0.609 0.918 0.000
Superficial Oil Vel. ft/min 72.1 17.8 0.0
Superficial Gas Vel ft/min 68.5 6.6 0.0
Step 8: Calculating downhole flowrates in BPD from superficial phase velocities
The superficial phase flowrates are in ft/min. To convert from ft/min to barrels per day we use the following equation: BPD = ft/min x Internal Diameter inches ^2 x 1.4. If we are using a continuous spinner in tubing the interpreter may wish to factor in the housing and spinner blade cross sectional area which by reducing flow area increases the fluid velocity adjacent to the spinner. In this example, using a FBS, we will ignore it. Depth ft RKB 8175 8300 8350
Superfi erfici cial al Oil Vel. ft/min 72.15 17.77 0.00
Superficial Gas Vel. ft/min 68.48 6.60 0.00
Tubular lar ID
Downhole Oil
Downhole Gas
inches 6.184 6.184 6.184
BPD 3862.7 951.6 0.0
BPD 3666.3 353.3 0
These flowrates are in downhole barrels they must next be converted to surface units. Step 9: Calculating surface flowrates flowrates in surface units from downhole flowrates in BPD
The units of measure downhole are in barrels, but at surface oil (and water) are in barrels but gas is in standard cubic feet. We also have to consider the gas that is in solution in the oil at downhole pressure and temperature that will be liberated from the oil at standard conditions (60 deg F, 15 psia) and so added to the total gas flowrate. For simplicity gas flowrate is in Mscfd. We have already listed the PVT properties of our fluids in step 4.: Oil Formation volume factor Oil solution GOR Gas Formation volume factor
1.42 Reservoir BBL / Standard BBL 666 standard cu ft / Standard BBL oil. 1.158 Reservoir BBL / MSCF.
We use the following volume corrections: Oil: STBOPD = Downhole Downhole oil / Oil formation volume factor Water (if used): STB Water = Downhole water / water formation volume factor Gas: mscfd gas = (Downhole (Downhole gas / Gas formation volume factor) + (STBOPD (STBOPD * (Oil Solution GOR/1000)) GOR/1000)) Depth Depth ft RKB 8175 8300 8350
Down Downhol hole e Oil BPD 3862.7 951.6 0.0
Down Downhol hole e Gas Gas BPD 3666.3 353.3 0.0
FVF FVF Oil Soln Soln GO GOR R FVF FVF Gas Gas Surfa Surface ce Flow Flow Oil Surfa Surface ce Flow Flow Gas Gas rb/stb scf/stb rb/mscf STBOPD MSCFD 1.42 666 1. 1.158 2720.23 4977.70 1.42 666 1.158 670.13 751.41 1.42 666 1.158 0.00 0.0
Step 10: Present the results in a format meaningful to the client
The flowrates flowrates we are generating generating are cumulative. cumulative. The The client is interested interested in zonal rates. Zonal Zonal rates are calculated by subtraction of the flowrate below the zone from the flowrate above the zone. It is also good practice to generate percentage contributions of each zone and gas-oil ratio (or water-oil ratio). Zone Zone Top Lower
Cumu Cumulativ lative e Oil STBPD 2720.2 670.1 0.0
Zona Zonall Oil STBPD 2050.1 670.1 0.0
Oil Contr Contribu ibution tion Cumula Cumulative tive Gas Gas Zona Zonall Gas Gas Gas Gas Contr Contribu ibution tion GOR GO R % MSCFD MSCFD % SCF/BBL 75.4 4977.7 4226.3 84.9 2061.5 24.6 751.4 749.5 15.1 1118.5 0.0 1.9 1.9 0.0 N/A
Refining the results
This analysis is apparently straight forward. However there are several variables which can lead to error. Therefore if we trust the surface reported flowrates and we have accurate PVT data these variables can be changed changed to refine refine our analysis to match 100% flow downhole downhole to surface reported reported rates. rates. With With judgem judgement ent these corrections can be applied to each of the zones Changing the flow profile correction factor: If we use a flow profile correction of 0.9 instead of 0.83, both the oil and the gas the flowrates are higher and the GOR decrease slightly. slightly. The total flow has no influence on the calculated holdup or slip velocity. Perf Perf Cumu Cumulativ lative e Oil Depths ST STBPD Top 2992.6 Lower 741.3 0.0
Zona Zonall Oil STBPD 2251.3 741.3 0.0
Oil Contr Contribu ibution tion Cumula Cumulative tive Gas Gas Zona Zonall Gas Gas Gas Gas Contr Contribu ibution tion GOR GO R % MSCFD MSCFD % SCF/BBL 75.2 5373.4 4566.9 85.0 2028.5 24.8 806.6 804.5 15.0 1085.3 0.0 2.0 2.0 0.0 N/A
This is a way to match total downhole rate to total rate derived from surface corrected to downhole conditions though there will be slight changes to GOR due to slip velocity remaining fixed. Changing the slip velocity: If we set the gas slip velocities to zero the oil rate is higher and the gas rate is lower. Lowering the slip velocity increases the heavy phase flowrate. Perf Perf Cumu Cumulativ lative e Oil Depths ST STBPD Top 3501.8 Lower 914.9
Zona Zonall Oil STBPD 2586.9 914.9
Oil Contr Contribu ibution tion Cumula Cumulative tive Gas Gas Zona Zonall Gas Gas Gas Gas Contr Contribu ibution tion GOR GO R % MSCFD MSCFD % SCF/BBL 73.9 5088.1 4378.8 86.1 1692.7 26.1 709.3 707.3 13.9 773.0
If we were to increase the gas slip velocity the gas rate would be higher and the oil rate lower. Thus it can be seen that in a situation where we have a standing water column with oil or gas bubbling up through it we can adjust the light phase slip velocity until the water rate is zero. A standing water column is when no water is produced at surface during flow. This is a way to match the downhole flowrates for each phase to match relative surface flowrates for each phase after correction from downhole conditions to surface conditions. Conclusion
Two phase analysis in vertical wells with accurate measurements is reasonably straight forward. However it can also be seen that in the dynamic flowing conditions occurring during production logging that the true nature of flow and the correction factors are unknown and have to be assumed. Sometimes PL analysis software will generate situations that cannot be true, for example oil disappearing into a zone while gas comes out of the same zone. This is where where the skill and experience of the interpreter in terpreter comes in. The best advice I can give is to start off looking looking at the data and forming a hypothe hypothesis sis before proceeding proceeding with the analysis. Often the first ideas about a PL interpretation are incorrect. Writing a description of the logging logging curves and how they change helps by making you think to explain why they change. change. Then perform the analysis such that the analysis results make sense compared to the log. This is not the ideal way as we should have no pre-conceived ideas before starting the analysis, but in reality it works best. Nick N.D.Ryan Sondex Training
