PAGINA WEB - PROYECTO 2025

INDEX

google.com, pub-8657610290366511, DIRECT, f08c47fec0942fa0

EARNED VALUE MANAGEMENT

It is one of the most used methods to measure project performance. It integrates the baseline costs (AC) and (PV), the scope (EV) and the schedule.

- Planned Value (PV) - Authorized budget that has been assigned to scheduled work.

- Earned Value (EV): Measure of the work performed in terms of the budget for that work.

- Actual cost (AC): Total cost incurred to carry out the work measured by earned value.

- BAC: Budget at completion

- EAC: Estimate at completion

- ETC: Estimate to complete

EAC = AC + (BAC – EV)

ETC = EAC – AC

EV =%Physical Advancement × BAC

Earned Value (EV) is the value of work performed expressed in terms of the approved budget allocated to such work for a scheduled activity or itemized work structure. Earned value is also called Budgeted Cost of Work Performed (BCWP).

If you were the director of the project, and the sponsor of the project asked you today in what situation the project is, what would you say? The first thing you could look at is that the real cost (AC) to date is higher than the earned value (EV), or what is the same, the value of the work done is below its real cost (Cost Variance CV = EV-AC <0). A priori, it might seem that this extra cost is not justified, but in order to reach that conclusion, we need to know what the project's progress status is compared to what was planned. Again, if we compare the earned value with the planned value (Schedule Variance SV = EV-PV <0), we realize that the earned value (EV) is also below the planned (PV), a symptom that the project You are not meeting the initially planned deadlines. Therefore, the project manager will have no choice but to inform the sponsor that the project has cost overruns and is behind schedule. Faced with this assertion, the sponsor asks the project manager what the final cost estimate of the project is upon completion. After making the appropriate calculations considering the current trend, the director / director of the project observes that the final forecast of EAC costs is higher than the project budget (see graph).

The Variation of Schedule SV (Schedule Variance): It is the difference between the EV and PV, that is, we compare the physical progress with that planned at a certain time, as a result we can infer that the project is behind or ahead of the planning:

SV = EV-PV

When SV is positive; ie EV> PV, we are creating more than we planned, we are doing better than expected. 😀

But if SV is negative; that is, EV <PV, we are creating less than we planned; I mean, we are behind. 😢 This is why it is called a schedule variance.

SPI (Schedule Performance Index):

This factor allows us to determine if progress is above or below the planned schedule and by what proportion:

SPI = EV / PV

When SPI> 1; that is, EV> PV, it happens the same as when SV is positive,

When 0 <SPI <1; that is, EV <PV, it happens the same as when SV is negative.

The Cost Variation

For example, it is exposed with the variable CV (Cost Variance), which aims to determine the space that exists between the physical progress and the actual cost executed:

CV = EV-AC

When CV is positive; that is, EV> AC, we are creating more than we spend, we are doing better than expected. 😀

But if CV is negative; that is, EV <AC, we are creating less than we spend; that is, we are over budget. 😢 That is why it is called a cost variance.

Performance Indices

- Schedule Performance Index (SPI). SPI = EV / PV

- Cost Performance Index (CPI). CPI = EV / AC

- To Complete Performance Index (TCPI). TCPI = (BAC - EV) / (BAC - AC).

Forecasts

Estimated at Completion (EAC). It is the forecast of the final cost. It can be calculated in different ways:

EAC = BAC - SV. Future costs will not be the same as those considered in the PMB because the cost variations were atypical.

EAC = BAC / CPI. Future costs will be calculated based on the cost performance efficiency ratio to date.

EAC = BAC / (CPI * SPI). Future costs will be calculated based on cost performance ratios and schedule to date.

EAC = AC + New estimate for remaining work.

Estimated to Complete (ETC). ETC = EAC - AC

Variation at Completion (VAC). VAC = BAC - EAC

VAC% = VAC / BAC

Cost Performance Index at Conclusion (CPIAC). CPIAC = BAC / EAC

There is an emerging approach that takes measurements based on time units rather than cost units to calculate schedule performance:

Time Estimate at Completion (EAC t). 

Forecast the duration of the project. It is recommended to obtain it from an analysis of the project network, although an approximate estimate of the final duration could also be obtained using the SPI, in case the trend continues: 

EACt = (BAC / SPI) / (BAC / Duration of the PMB) = Duration of the PMB / SPI

Time Variance at completion (VACt). VACt = Duration of PMB - EACt

VACt% = VACt / Duration of PMB

Time Schedule Performance Index at Conclusion (SPIACt). SPIACt = Duration of PMB / EACt

PROJECT EVALUATION

RISK ASSESSMENT FOR OIL AND GAS PROJECT 

Risk assessment can be used in many ways. In oil and gas construction activity focus about the safety risk assessment , which in general is qualitative. For the project management it can be used in cost estimation to define the contingency.  There are many softwares that are based on Monte-Carlo simulation, the best one is the Crystal-ball software.

Exploration Risk :

– Existence of Hydrocarbons

– Magnitude of Discovery

– Type of Hydrocarbon

Development Risk :

– Technical Risk 

– Reservoir Development

The ALARP principle - as low as reasonably practicable

The ALARP principle is sometimes used in the oil and gas industry . The use of the ALARP principle may be interpreted as, satisfying a requirement to keep the risk level “as low as possible” provided that the ALARP evaluations are extensively documented. In the ALARP region (between “lower tolerable limit” and “upper tolerable limit”), the risk is tolerable, only if risk reduction is impracticable or if its cost is grossly disproportionate to the improvement gained. The common way to determine what is practicable is to use cost–benefit evaluations as a basis for the decision on whether certain risk reducing measures should be implemented. A risk may not be justified in any ordinary circumstance, if it is higher than the “upper tolerable limit.” The “upper tolerable limit” is usually defined, whereas the “lower tolerable limit” may sometimes be left undefined. This will not prohibit effective use of the approach, as it implies that ALARP evaluations of risk reducing measures will always be required. The ALARP principle used for risk acceptance is applicable to risks regarding personnel, the environment, and assets.

Layers of Protection Analysis (LOPA)

Percentil P10, P50, Pmean, P90 : 

One technique that the industry uses to understand and quantify distributions of data is percentiles (or cumulative probabilities). This organizes the distribution into increments between 0 and 100. For example, the 10th percentile or P10 number  say 10 percent of my wells will have a value “less than or equal to” my P10 value. The location of percentiles on a typical lognormal distribution would look something like:

Comparing to the P10, which could potentially give estimates that are over-optimistic, and the P90, a conservative estimate which could potentially leave too much oil, both providing confusing future trends. It is a common misunderstanding that the P50 is a synonym of P mean. This will be true is the probability distribution function for the observations were symmetrical. In this case, the mode, P mean and P50 would all be the same.

CAPEX : Capital expenditures are major purchases a company makes that are designed to be used over the long-term. 

- Platform   : Services + Materials + Logistic

- Well         : Drilling Cost ( Services + Tangibles) 

- Facilities  : Lines + Tanks + Separators 

OPEX : Operating expenses are the day-to-day expenses a company incurs to keep their business operational.

- Rent and utilities

- Wages and salaries

- Accounting and legal fees

- Royalties 

- Property taxes

- Business travel

Lifting Cost = OPEX / Production ( $/bbl ) 

1.- Cash flow (n=0) : CAPEX

2.- Cash flow (n=1) : Oil Price ( PRMS or Portfolio )  x Q ( Oil Production) -  OPEX | Year 1

3.- Cash flow (n=2) : Oil Price ( PRMS or Portfolio )  x Q ( Oil Production) -  OPEX | Year 2

PETROLEUM RESOURCE MANAGEMENT SYSTEM (PRMS) 

In 2000, the American Association of Petroleum Geologists (AAPG), SPE, and the World Petroleum Council (WPC) jointly developed a classification system for all petroleum resources. This was followed by complementary application evaluation guidelines (2001), standards for estimation and Audit of Reserves information (2001, 2007 revised version) and a glossary of terms used in the definitions of resources (2005).

(*) For Oil Production : Require to have database production data  in OFM Software for example. 

ARPS

Exponential Declination ( b=0)   : 

Hiperbolic Declination ( 0<b<1)  : 

Switch Point : change Transient flow to Boundary flow.

EUR : using declination curve : ARPS , Fetkovich, Duong, etc...  Depend of reservoirs type. 

SPE/WPC/AAPG (2000) : 

- Proved    >= P90 (1P)

- Probable >= P50 (2P)

- Possible >=  P10 (3P)

OOIP & OGIP

· N = OOIP (STB)

· 7758 = conversion factor from acre-ft to bbl

· A = area of reservoir (acres) from map data

· h = height or thickness of pay zone (ft) from log and/or core data

· ø = porosity (decimal) from log and/or core data

· S_w = connate water saturation (decimal) from log and/or core data

· B_oi = formation volume factor for oil at initial conditions (reservoir bbl/STB) from lab data

· G = OGIP(SCF)

· 43560 = conversion factor from acre-ft to ft3

· B_gi = formation volume factor for gas at initial conditions (reservoir ft3/SCF)

·         Solution gas                   : 18 – 25%

·         Expansion                      : 2 – 5%

·         Gas cap drive                 : 20 – 40%

·         Water Drive (bottom)      : 20 – 40%

·         Water Drive (Edge)         : 35 – 60%

·         Gravity                            : 50 – 70%

 

 

Recovery Oil reserve = OOIP or OGIP x RF

                   

NET PRESENT VALUE (NPV) : 

Net Present Value (NPV) is the value of all future cash flows (positive and negative) over the entire life of an investment discounted to the present.

"D" represents the value of the cash flows for each of the exercises, "i" the interest rate expected to be obtained or the rate of return of an investment of risk and similar duration and "n" the number of periods that it is estimated of the operation of the company.

Cash Outflows (expenditure)

• Initial investment to purchase assets
• Operating costs such as labor and materials
• Tax payments
• Project management expenses
• Any other outflow caused by accepting the project

Cash Inflows (income)

• Project revenues and grants
• Eventual scrap value of assets
• Any other inflow caused by accepting the project

             

CRYSTAL BALL CHART

- Red área = Cash Flow negative

- Blue área = Cash flow positive

CONTRIBUTION TO THE VARIANCE NPV

google.com, pub-8657610290366511, DIRECT, f08c47fec0942fa0

LOGISTIC

ICC ( International Chamber of Commerce)  has launched Incoterms 2020 , the newest edition of the renowned trade terms for the delivery of goods, providing certainty and clarity to business and traders everywhere. Incoterms 2020 includes more detailed explanatory notes with enhanced graphics to illustrate the responsibilities of importers and exporters for each Incoterms rule. The introduction to Incoterms 2020 also includes a more detailed explanation on how to choose the most appropriate Incoterms rule for a given transaction, or how a sales contract interacts with ancillary contracts.

MI vs CHINOOK ( HEAVY LIFT) 

IMPROVED LIFT CAPABILITY 

ENHANCED LANDING APPROACH CAPABILITY

SMALLER ROTOR BLADE

DOWNWASH IMPACT

google.com, pub-8657610290366511, DIRECT, f08c47fec0942fa0

DRILLING RIGS 2

DRILLING BARGES : A drilling barge consists of a barge with a complete drilling rig and ancillary equipment constructed on it. Drilling barges are suitable for calm shallow waters (mostly inland applications) and are not able to withstand the water movement experienced in deeper, open water situations. When a drilling barge is moved from one location to another, the barge floats on the water and is pulled by tugs. When a drilling barge is stationed on the drill site, the barge can be anchored in the floating mode or in some way supported on the bottom. The bottom-support barges may be submerged to rest on the bottom or they may be raised on posts or jacked-up on legs above the water. The most common drilling barges are inland water barge drilling rigs that are used to drill wells in lakes, rivers, canals, swamps, marshes, shallow inland bays, and areas where the water covering the drill site in not too deep.

SUBMERSIBLES RIGS: Submersible drilling rigs are similar to barge rigs but suitable for open ocean waters of relative shallow depth. The drilling structure is supported by large submerged pontoons that are flooded and rest on the seafloor when drilling. After the well is completed, the water is

pumped out of the tanks to restore buoyancy and the vessel is towed to the next location. 

JACK - UP RIGS: 

Jack-up drilling rigs are similar to a drilling barge because the complete drilling rig is built on a floating hull that must be moved between locations with tug boats. Jack-ups are the most common offshore bottom-supported type of drilling rig. Once on location, a jack-up rig is raised above the water on legs that extend to the seafloor for support. Jack-ups can operate in open water or can be designed to move over and drill through conductor pipes in a production platform. Jack-up rigs come with various leg lengths and depth capabilities (based on load capacity and power ratings). They can be operated in shallow waters and moderate water depths up to about 450 ft.

SEMI - SUBMERSIBLE RIG: Semi-submersible drilling rigs are the most common type of offshore floating drilling rigs and can operate in deep water and usually move from location to location under their own power. They partially flood their pontoons for achieving the desired height above the water and to establish stability. “Semis” as they are called may be held in place over the location by mooring lines attached to seafloor anchors or may be held in place by adjustable thrusters (propellers) which are rotated to hold the vessel over the desired location (called dynamically positioned).

DRILLSHIP:   Drillships are large ships designed for offshore drilling operations and can operate in deepwater. They are built on traditional ship hulls such as used for supertankers and cargo ships and move from location to location under their own power. Drillships can be quite large with many being 800 ft in length and over 100 ft in width. Drillships are not as stable in rough seas as semi-submersibles but have the advantage of having significantly more storage capacity. Modern deepwater drillships use the dynamic positioning system (as mentioned above for semisubmersibles) for maintaining their position over the drilling location. Because of their large sizes, drillships can work for extended periods without the need for constant resupply. Drillships operate at higher cruising speeds (between drillsite locations) than semi-submersibles.

WELL SERVICES ENGINES

Drilling rigs use direct current generators and motors that have an approximate efficiency of 68%. Actual efficiency in conjunction with drilling machinery is 87.5% due to additional losses in the power requirements of field induction generators, cooling blower, commutator temperature, brushes, and feeder cable length. In this system, the available energy is limited for the reason that only one DC generator. can be electrically linked to a DC motor. resulting in 1600 H.P. available to drive the winch. 

DC (SCR) Drilling Rig

On a DC drilling rig, alternate current (AC) produced by one or more AC generator sets is converted into direct current (DC) by means of a silicon-controlled-rectifier (SCR) system. They obtain an efficiency of 68%; whose available energy is concentrated in a common bar (PCR) and can be partially or totally channeled to the drilling machinery (rotary, winch and pumps) that is required.

AC (VFD) Drilling Rig On an AC powered rig, AC generator sets (diesel engine plus AC generator) produce alternating current that is operated at variable speed via a variable-frequency drive (VFD)

AC versus DC Drilling Rig

Apart from being more energy efficient, AC powered rigs allow the drilling operator to more accurately control the rig equipment, thus enhancing rig safety and reducing drilling time.

AC Drilling Rig Advantages

- Efficient energy consumption due to a high power factor (minimum 95%).

- Precise speed regulation over a wider speed range.

- Constant high power even at low speed.

- Full torque at zero speed.

- Regenerative braking for safe and efficient control of the drawworks.

- Convenient and safe autodriller system for managing and controlling parameters such as weight on bit (WOB), rate of penetration (ROP), and rotary torque control.

CAT 3512B : Average rating: 1000 kw 

CAT 3512B : Average rating: 1000 kw 

google.com, pub-8657610290366511, DIRECT, f08c47fec0942fa0

DIRECTIONAL 2

VIBRATION IN BOTTOM HOLE ASSEMBLY

When drilling a well there is a risk of serious damage caused by drillstring vibrations. Shock and vibration are identified as a cause of premature failure on drill bit and components in the bottom hole assembly (BHA), resulting in lost time for operators and costing service companies several millions in repair each year. The expenditures incurred by drillstring vibrations include reduced rate of penetration (ROP), tripping and poor drilling performance. Currently, several tools and techniques are used in the attempt to minimize shock and vibration. For vibration mitigation to be more effective in the future, the most effective tools and techniques must be designated, implemented and improved.

Predicting bottom hole assembly (BHA) vibrations is a complicated problem. Axial, lateral, and torsional vibrations can be coupled and effects such as stick-slip and whirl can magnify the loads. Fatigue, pipe bouncing, and tool joint washouts demon e the complexity of the problem. One type of vibration that can be isolated and analyzed is the rapid destruction of the BHA caused by operating at or close to resonance. At rotating speeds that reinforce the natural vibration of the BHA, the destructive harmonics generate high stresses resulting in very short fatigue life. While other factors may cause BHA failure, a significant percentage of field failures appear to be associated with harmonic vibration, particularly lateral vibration. A simplified model based on harmonic analysis using finite elements has been found to agree well with field experience. The influence of stabilizer placement, drill string forces, and mass of the drilling mud are included in the finite element vibration model. (SPE-16675-MS)

AXIAL VIBRATION : Can cause bit bounce , which may damage bit cutter and bearing.

TORSIONAL VIBRATION : Can cause irregular down - hole rotation. Stick/Slip is often seen while drilling and is a severe form of drillstring torsional oscillation in which the bit becomes stationary for a period. Torsional fluctuations fatigue Drill collars connections and can damage bits. The use of the mud motor may help to address if the main source of excitation is from the bit but the presences of a motor does not prevent stick/slip . The drillstring and BHA  above the motor can enter into a stick/Slip motion even when the motor is turning the bit a steady rate.  

LATERAL VIBRATION : are most destructive type of vibration and an create large shocks as the BHA impacts the wellbore wall. The interaction between BHA and drillstring contact points may, in certain circumstances , drive the system into backward whirl. Backward whirl is the most severe form of vibration, creating high - frequency and large - magnitude bending moment fluctuations that result in high rates of components and connections fatigue. Imbalance in an assembly will cause centrifugally induced bowing of the drillstring , which may produce forward whirl and result in one - side wear of components.  

   

1.- Schlumberger

2.- Halliburton 

SUMMARY

Stick-slip and whirl are vibrational problems that limit drilling performance in hard formations and extended reach wells. When these vibrations are present, adding roller reamers to the drillstring can significantly reduce their severity and improve performance. Whirl is characterized by lateral vibration at the bit and in the BHA. When whirl becomes severe, lateral vibrations cause significant side forces in stabilizers. Frictional drag then causes high torque levels at the stabilizers, which can result in stick-slip (fluctuations in BHA rotational speed). This is referred to as “coupled stick-slip.” When these conditions exist, the replacement of stabilizers with roller reamers reduces torque generation at the contact points. Consequently, more torque becomes available to the bit and the driller may raise WOB. This results in reduced bit whirl and improved ROP. The reduction of bit whirl and elimination of stick-slip prevent damage to bit and BHA components

Figure5 shows diagram for each of the three BHA configurations. Note that there are two stabilizers configured in BHA-2. The stabilizer is located at the far left to the bit in BHA-3 compare with BHA-2. There is one stabilizer used in BHA-1 near the bit. The detail descriptions are as following:

 

Figure6 provides state vectors display comparison for three of BHA surrogates operation at 100RPM and 80000N of bit weight. The lateral vibration potential simulation for BHA-1 is significantly lower than BHA 2 and BHA-3. Especially for the lateral displacement, the effect is most remarkably, which means that the contacts for BHA-1 with wellbore may be less than other BHA surrogates during drilling process. However, the yellow color curve shows the larger amplitudes of the states for BHA-2 than others, which represents the most severe vibration potential.

Cómo calcular el MTBF ( MEAN TIME BETWEEN FAILURES)

El cálculo del MTBF se hace con base en la diferencia entre el tiempo total disponible y el tiempo perdido, dividiendo por el número de paradas. La fórmula se representa con la siguiente expresión:

EJEMPLO : MTBF Y MTTR

STABILIZER

The stabilizers can be run either near bit or up in the drill string

google.com, pub-8657610290366511, DIRECT, f08c47fec0942fa0

DRILLING BITS 2

DRILL BITS

BIT PROFILE

BACK RAKE

FUERZAS SOBRE EL CORTADOR: 

LEACHING

CUTTER WEAR

MSE MODEL FOR ROTATING DRILLING WITH PDM

MSE has been defined as the mechanical work done to excavate a unit volume of rock.

Unconfined compressive strength (UCS)

Laboratory experiment showed that MSE was numerically close to the unconfined compressive strength (UCS) of the formation at maximum drilling efficiency [6]. However, the tests were conducted at atmospheric conditions.

Confined compressive strength (CCS) 

In the real drilling process, MSE is numerically close to the CCS of the formation at maximum drilling efficiency. In other words, when drilling achieves a maximum drilling efficiency, the minimum MSE is reached and is roughly equal to the CCS of the rock drilled

Therefore, MSE can be used to detect the peak drilling efficiency by surveilling MSE to see if the MSE(min) is roughly equal to the CCS of the rock drilled. 

Although torque at the bit can be easily measured in the laboratory and with Measurement While Drilling (MWD), the majority of field data is in the form of surface measurement.While in the absence of reliable torque at the bit measurements, the calculation of MSE based on this model contains even large sources of error. Therefore, it is only used qualitatively as a trending tool.

μb   : bit-specific coefficient of sliding friction

Db  : bit diameter (in)

T     : torque at bit (ft-lbf)

Em  : mechanical efficiency of new bit

Ab   : bit area (in2)

DRILLING PERFORMANCE

3D CUTTER

SCHLUMBERGER

BAKER HUGHES

NOV( REED HYCALOG)

VAREL 

google.com, pub-8657610290366511, DIRECT, f08c47fec0942fa0