System and method for optimizing drilling speed

“SYSTEM AND METHOD TO OPTIMIZE THE PERFORATION SPEED” j 223126 j APP / FHCR

Requested by:

HALLIBURTON ENERGY SERVICES, INC, wAidettte c * t 2600 South 2nd Street, Duncan, Oklahoma 73536-0440, EU AMERICA j

SYSTEM AND METHOD TO OPTIMIZE THE DRILLING SPEED

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Field of the Invention

The present invention relates to a system and method for optimizing the penetration rate when drilling in a geological formation by using data on modeled and actual well pressure values ​​to determine the highest penetration rate at which it can be Perform drilling safely.

Description of Related Technology

Oil and natural gas are fossil fuels found in certain geological formations. They are crucial sources of energy, and are used for many other chemical applications. Due to the high demand for oil and natural gas, elaborate techniques have been developed to drill on the surface of the earth to reach oil and natural gas deposits. In many cases these deposits are thousands, or even tens of thousands of feet below the surface. Likewise, deposits are generally placed below the ocean floor.

Once a potential oil or natural gas deposit has been detected, a drilling platform is established to form a well in the formation. The drilling rig includes energy systems, mechanical motors, a rotating piato drill, and a circulation system that circulates a fluid, sometimes called “mud”, along the well. The fluid serves to remove materials as the trephine loosens them from the surrounding rock during drilling and to maintain adequate well pressure. For his

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put, a drilling rig is a complex and expensive machinery.

223.116

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The drilling itself is carried out by using a trephine at the bottom of the duct (drill string) and transmitting the rotary movement to the trepan using a known multilateral pipe horn like Kelly (square transmission shaft) with a rotating piato. As the drilling progresses, the mud circulates through the pipeline to the well and parts of the rock are removed from the well by the circulating mud. As drilling continues, new sections are added to the pipeline progressively. The drilling will be completed when the desired depth is reached, at which time several tests can be carried out to accurately locate and isolate the depth of the formation that houses the desired hydrocarbon deposits.

However, the drilling process is extremely expensive and takes a long time. The operation of an offshore platform can easily cost $ 500,000 per day. Therefore, small time savings can lead to large monetary savings. Drilling faster, of course, saves a lot of time because drilling time could be reduced, which leads to a phase of “production” of oil wells more quickly.

It is important to properly handle the pressure of the well during drilling, to ensure that the drilling process leads to a stable well. If there is too much fluid pressure during drilling, there may be insufficient margins between fracture formation and pore pressures, which can result in formation damage and production difficulties. If the pressure is low, an explosion may occur. This scenario is dangerous and potentially expensive to cure. However, there is an incentive to drill as fast as possible, because this saves time and, consequently, costs. However, drilling faster makes it more difficult to respond adequately to changes in well pressure. It's hard

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Determine the penetration rate that is fast optimally and still safe.

SYNTHESIS OF THE INVENTION

The invention uses real-time information on the pressure obtained while drilling in a geological formation and analyzes it in combination with the equivalent circulation density (ECD) data modeled for the drilling process based on the Statistical analysis to estimate the safe penetration rate. The equivalent circulation density is the effective density exerted by a circulating fluid (the mud) against the formation that takes into account the pressure stock due to the differential pressure between the well and the surface. The equivalent circulation density can be calculated from an annular pressure measurement (circulating mud pressure) taken at a position selected in the annular section based on the familiar expression for the hydrostatic pressure of a fluid column: p-pgh p represents the pressure, p represents the density of the fluid, g represents gravity, and h represents the vertical depth of the position at which the pressure is measured. Solving the above expression provides the following expression for equivalent circulation density:

ECD = p / gh

The equivalent circulation density can be determined through the use of sensors, or modeled through the use of a computer model. Either way, it reflects the pressure that the mud puts on the well as drilling continues.

The purpose of the present invention is to maximize the productivity of drilling initiatives. Productivity is usually determined by

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the relationship between platform time (drilling time) to the NPT (Non-Productive Time); When drilling a well, it is convenient to maximize this relationship because there is a cost associated with the NPT while only platform time is a productive and useful way to spend money. Also, due to the costs associated with any type of time, it is convenient to minimize both forms of time, and one way of doing so is to have a higher penetration speed.

One embodiment utilizes selective drilling compression / expansion activity (SDACE) of historical real-time data coupled with one with a prediction drill simulator, such as Halliburton ™ DFG ™ Software with DrillAhead® Hydraulics Module. By involving the mathematical and statistical analysis to combine these two sources of information on an ongoing drilling project, the invention can develop projections on which equivalent circulation density values ​​will be the maximum tolerable equivalent circulation density values ​​for the drilling process in action. Based on what is practical for a given drilling process, estimates can then be used to increase penetration speed. This will allow greater productivity by allowing a safe increase in penetration speed.

According to an embodiment of the invention, there is provided: a method for optimizing drilling penetration speed and performance when drilling in a geological formation, comprising the steps of: collect real-time PWD (drilling pressure) data from a drilling rig sensor, such as a background string of MWD (drilling measurement), acquire equivalent density density data modeled for the drilling process, calculate standard deviation of the data differences of said real-time drilling pressure and said equivalent circulation density

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modeled; calculate a set of maximum tolerable equivalent circulation density data based on the calculated deviation, and determine the penetration speed of a drilling string of a platform based on the maximum tolerable equivalent circulation density data of the process of drilling.

In accordance with another embodiment of the invention, there is provided: a system for optimizing drilling penetration speed and performance when drilling in a geological formation, comprising: a collection unit for collecting real-time drilling pressure data from a drilling rig sensor, such as a drilling measurement bottom string, an acquisition unit for acquiring data of equivalent circulation density modeled for said drilling process. drilling, a unit of calculation to calculate the standard deviation of the differences in data of said real-time drilling pressure and said modeled equivalent circulation density, a unit of calculation for calculating a set of maximum predictable equivalent equivalent circulation density data for said drilling process based on the calculated deviation, and a control unit for controlling the penetration speed of the drilling rig of the platform based on the data of the maximum tolerable equivalent circulation density of the drilling rig well.

In accordance with another embodiment of the invention there is provided: an apparatus for optimizing penetration drilling speed and performance when drilling in a geological formation, comprising: means for collecting real-time drilling pressure data from a drilling rig sensor, such as a drilling measurement bottom string, means for acquiring equivalent circulation density data modeled for said drilling process, means for calculating the deviation Ias standard

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data differences of said real-time drilling pressure and said modeled equivalent circulation density, means for calculating a set of maximum predictable equivalent circulation density data for said drilling process based on the calculated deviation, means for determining the penetration speed of the drilling rig of the platform based on the maximum tolerable equivalent circulation density data of the drilling process.

According to another embodiment of the invention, there is provided: computer reading medium, which has instructions stored therein, where the instructions, when executed by a processor, perform computer functions designed to optimize the penetration speed in the perforation. and performance when drilling in a geological formation, which includes the stages of: collect real-time drilling pressure data from a drilling rig sensor, as well as bottom drilling string data, acquire equivalent circulation density data modeled for the drilling process, calculate the standard deviation of the differences in data from said real-time drilling pressure and said modeled equivalent circulation density, calculate a set of maximum predictable equivalent circulation density data for the drilling process based on the calculated deviation, and determine the penetration speed of the drilling rig of the platform based on the equivalent circulation density data maximum tolerable drilling process.

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BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a graph that shows ECD values ​​vs. corresponding time with the PWD (drilling pressure) so how a model and how they compare with the fracture gradient.

FIG. 2 is a graph that shows ECD values ​​vs. corresponding time with PWD (drilling pressure) measured as a model and as can be used to estimate a maximum ECD curve that remains below the fracture gradient.

FIG. 3 is a graph showing a hypothetical ECD if the ROP (penetration speed) will be increased by 100% in the perforation, and shows that it remains below the maximum ECD curve, which is below the fracture gradient.

FIG. 4 is a graph that shows various time and money savings that would result from different levels of drilling aggressiveness (ie, several increases in drilling speed).

FIG. 5 is an example of real-time data from real wells.

FIG. 6 is a block diagram of a computer system of an embodiment.

FIG. 7 is a flow chart of a method of one embodiment.

DETAILED DESCRIPTION OF THE INVENTION

In the following description, numerous specific details are set forth in order to provide a thorough understanding of the present invention. It will be apparent, however, to one skilled in the art, that the present invention can be carried out without some or all of the specific details. In other cases, well-known steps have not been described in detail in order not to obscure the present invention unnecessarily.

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In a drilling process, tremendous pressures are generated in the well, which must be handled carefully. There must be a careful balance between drilling as fast as possible, which saves valuable time, and preserves the integrity of the drilling operation, by avoiding bills or an explosion. One of the objectives of the invention is that it be used to help those involved in drilling to make decisions that will help determine an optimized drilling penetration rate.

The invention carries out this optimization by using real-time drilling pressure data 103 of the well, which is generally shown in a line diagram as in FIG. 1. This graph presents the equivalent circulation density data 101, which is Equivalent Circulation Density, a way of measuring the Drilling Pressure.

As illustrated in FIG. 6, which shows a block diagram of an embodiment of a computer system, the collection unit 601 collects real-time drilling pressure data from a drilling platform, (through a bottomhole sensor as a bottom string of drilling measurement, for example) and an acquisition unit 602 acquires equivalent circulation density data modeled for the drilling rig. An exemplary way of acquiring modeled equivalent density density data is to use modeling software, such as DFG ™ Software with the Halliburton ™ DrillAhead® Hydraulics Module, which will provide a “prediction” model in which future drilling conditions are predicted.

Once the collection unit 601 and the acquisition unit perform their tasks, the information they provide can be used for a calculation unit 603 to calculate the standard deviation of data differences from said real-time drilling pressure and said density of modeled equivalent circulation and calculate a density data group of

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Maximum predictable equivalent circulation for each drilling process based on the deviations calculated as described in greater detail below. Finally, this information is transmitted to a control unit 604 to control the drilling rig based on the maximum tolerable equivalent circulation density data of the drilling process.

Returning to FIG. 1, the fracture gradient 105 is clearly very far to the right, that is, higher in the equivalent circulation density value of the drilling pressure curve 103 and the model 104 curve. The inventors' work has shown that using the standard deviation of measured drilling pressure and modeled equivalent circulation density, estimates can be made on how close to the fracture gradient it can be operated reliably during the drilling process. The less the standard deviation is, the more confidence you have to operate near the fracture gradient.

More specifically, the unit of calculation can use the traditional definition of standard deviation:

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Equation 1: »

In this equation 1: Xbar is the average of the drilling pressure data and Xi are the results of discrete models for a certain period. Once a standard deviation is computed and a standard sense of error is established, one can determine the maximum limits of optimization simulations. Using equation 2:

Equation 2: ECD_morexima = FG - (RF * σ + SF)

The fracture gradient data can come from different sources. Generally one will know the fracture gradient based on wells

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of reference and well tests performed on them. There are also various programs that attempt to model and predict the pore pressure and the fracture gradient based on various properties, such as the type of rock, porosity, temperature, etc. A good reference on the prediction of fracture gradients is: Pressure Regimes in Sedimentary Basins and Their Prédiction by Alan R. Huffman, Glenn L. Bowers, American Association of Petroleum Geologists, American Association of Drilling Engineers, American Association of Petroleum Geologists, American Association of Drilling Engineers Houston Chapter.

In Equation 2, RF represents the reliability factor and SF represents a safety factor. The safety factor depends on many factors including the risk (cost) of exceeding the equivalent circulation density and mitigating costs. The reliability factor is based on the number of standard deviations. If we assume a normal distribution for an RF = 1 approximately 68% of the values ​​would fall in the range. For an RF = 2, approximately 95% of the values ​​would fall in the range for and for RF = 3 approximately 99%. A reasonable safety factor coupled with an acceptable reliability factor would ensure that the equivalent circulation density remains below the fracture gradient by a safe margin. The user of a given embodiment chooses a reliability factor and a safety factor to reflect the margin of error that is considered acceptable. The standard deviation in real time, σ, can be calculated based on a previous “window” of drilling using one or several methods, as an average moving over the well, current auger run, or current formation. Any instability in the standard deviation could immediately be factored in the process of optimization by a calculation of the ECDmax11

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FIG. 2 shows the ECD_max 203 calculated and the safe operating range with a safety factor included. Once again, it is equivalent circulation density 201 vs. time 202, with recorded drilling pressure 204. The shaded area 205 shows the range of opportunity to increase the equivalent circulation density and maximize penetration speed.

The sediments (cuttings) generated during the drilling process must be transported to the surface by drilling the fluid in the annular section. The faster the penetration rate, the higher the sediment concentrations in the drilling fluid. As the sediment concentration increases, the average density of the drilling fluid also increases. The increase in the density of the drilling fluid will cause the hydrostatic component of the pressure exerted by the drilling fluid to also increase. In addition to the increase in density, there will also be an increase in effective viscosity. The increase in viscosity will also manifest itself in higher well pressures. Therefore, a higher penetration speed leads to a higher equivalent circulation density for these reasons. Historically, a sediment concentration limit of approximately 5% has been recommended for vertical wells. As wells have generally had a broader scope, recommendations for sediment concentrations have been reduced to less than 3%.

In real-time historical data, not all activities can or should undergo the understanding or expansion of time. For example, connection times are reduced by the physical time required to handle the pipes. On the other hand, drilling can generally be accelerated or slowed down; This is why the term "selective time understanding". Also, the various elements of the drilling process, such as “pump and rotate” to

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Well cleaning as well as other drilling elements may have different amounts of expansion and / or time understanding throughout the simulation for various intervals.

In the following table of historical real-time data, an example with two drilling activities is shown. In this case the drilling activity is followed by a pipe connection activity and then again by drilling. It is important to indicate that generally large amounts of data are recorded in small increments of time; Typically up to once per second. These elements are then combined and represented together for the purposes of simplicity.

Table 1: In this method one can select individual time elements and artificially compress or expand the time that a specific activity requires. Therefore, one can effectively change the penetration rate of historical data in preparation to put them in a simulator to predict equivalent circulation density, if the operator had drilled a higher speed. In this example the connection time remains constant while the penetration rate is redoubled. The modified time base data would then be the following. Note that the penetration speed can be determined by means of a sensor installed in the trephine that informs the speed at which drilling is carried out successfully.

<td>Weather</td><td>Activity</td><td>Depth</td><td>Pressure of</td><td>Speed</td>

<td>Past</td><td></td><td></td><td>Drilling</td><td>Penetration</td>

<td> 00:00:00</td><td>Drilling</td><td> 1000</td><td> 12</td><td></td>

<td> 00:20:00</td><td>Drilling</td><td> 1050</td><td> 12</td><td> 150</td>

<td> 00:40:00</td><td>Drilling</td><td> 1100</td><td> 12</td><td> 150</td>

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<td> 00:40:01</td><td>Connection</td><td> 1100</td><td> 11,5</td><td> 0</td>

<td> 00:45:00</td><td>Connection</td><td> 1100</td><td> 11,5</td><td> 0</td>

<td> 00:45:01</td><td>Drilling</td><td> 1100</td><td> 12</td><td> 150</td>

<td> 00:65:00</td><td>Drilling</td><td> 1150</td><td> 12</td><td> 150</td>

<td> 00:85:00</td><td>Drilling</td><td> 1200</td><td> 12</td><td> 150</td>

Table 2: The DAH simulator uses these modified historical data to recreate a real-time comparison of modeled equivalent circulation density data with respect to historical drilling pressure. In this case the predicted equivalent circulation density would be correct and could be plotted in real time with the actual drilling pressure and the equivalent circulation density modeled as shown in FIG. 3 in 304.

<td>Weather</td><td>Activity</td><td>Depth</td><td>Speed</td><td>from</td>

<td>Past</td><td></td><td></td><td>Penetration</td><td></td>

<td> 00:00:00</td><td>Drilling</td><td> 1000</td><td></td><td></td>

<td> 00:10:00</td><td>Drilling</td><td> 1050</td><td> 300</td><td></td>

<td> 00:20:00</td><td>Drilling</td><td> 1100</td><td> 300</td><td></td>

<td> 00:20:01</td><td>Connection</td><td> 1100</td><td> 0</td><td></td>

<td> 00:25:00</td><td>Connection</td><td> 1100</td><td> 0</td><td></td>

<td> 00:25:01</td><td>Drilling</td><td> 1100</td><td> 300</td><td></td>

<td> 00:35:00</td><td>Drilling</td><td> 1150</td><td> 300</td><td></td>

<td> 00:45:00</td><td>Drilling</td><td> 1200</td><td> 300</td><td></td>

Basically, FIG. 3 shows a plot of 300 ECD maximum lines 301, drilling pressure 302, and Model 303 data as well as the equivalent circulation density with a 100% increase in penetration speed.

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ECDmax 301 shows that such an increase is possible, and clearly the depth can be reached safely in 45 minutes instead of 85 minutes.

FIG. 4 represents 3 scenarios while drilling penetration speed is progressively increased. A line graph 400 shows the MD (measured depth) vs. ECDmax 403, drilling pressure 404 and equivalent circulation density Modeled 405. In 402 there are 3 scenarios, marked as Scenarios 1, 2 and 3 that show how progressively going faster and faster (and at the same time staying below the fracture gradient) you can save USD 12,500, USD 20,830, or USD 29,160; depending on drilling conditions. The particular conditions behind these higher penetration rates are not important; The important point behind these scenarios is that the realizations provide the user with increasingly fast thresholds that they can choose to implement and that can lead to a fast and safe drilling as long as the drilling remains within the calculated limits. Therefore, the embodiments suggest that the maximum thresholds for drilling speeds and predict what the drilling results will be at intermediate drilling speeds. The embodiments can be designed to simply drill as fast as possible (given the limits of the platform and the well, or provide the information to the drills and allow them to choose).

Current equivalent density density 402 data for drilling pressure 404, equivalent circulation density model 405 and measured depth 401 are continuously updated as drilling progresses. FIG. 4 shows three prediction auger scenarios at 406, 407, 408 (F, G, H). It also shows the depth of interval J 409, which

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provides information that will allow the choice of one optimization scenario with respect to the other.

In the table below (Table 3) is another example of SDACE (Compression / Expansion of Selective Activity) can be imposed in real time data. In this example, 50% penetration speed combined with a 25% increase in circulation time (well cleaning). In this case, time is saved because the drilling speed is increased. However, part of the time is sacrificed for the well cleaning time. Regardless, on a high seas platform of USD 500,000 per day, this simple example would translate into a time in minutes of 17.5 which would be equivalent to approximately USD 6076. Note that this is only considering about an interval of one hour. If it is repeated on a full day this would amount to savings of USD 145,824.

<td>Weather</td><td>Comp /</td><td>State</td><td>Speed</td><td>Speed</td><td>Savings of</td>

<td>Past</td><td>Exp /</td><td></td><td>from</td><td>from</td><td>Weather</td>

<td>(H / M / S)</td><td>Weather</td><td></td><td>Penetration</td><td>Penetration</td><td>Potentials</td>

<td></td><td>Will pass</td><td></td><td>Reai</td><td>Compressed</td><td></td>

<td></td><td>do</td><td></td><td></td><td></td><td></td>

<td> 0:00:00</td><td> 0:00:00</td><td>Drilling</td><td> 80</td><td> 120</td><td></td>

<td> 1:00:00</td><td> 0:40:00</td><td>Drilling</td><td> 80</td><td> 120</td><td> +00:20:00</td>

<td> 1:00:01</td><td> 0:40:01</td><td>Circulation</td><td> 0</td><td> 0</td><td></td>

<td> 1:10:00</td><td> 0:52:30</td><td>Circulation</td><td> 0</td><td> 0</td><td> -00:02:30</td>

<td> 1:10:01</td><td> 0:52:31</td><td>Drilling</td><td></td><td></td><td></td>

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FIG. 5 presents an expected equivalent density density graph with a selective time understanding of the drilling process that is used to create higher penetration speed simulations.

In these simulations, the penetration speed data has been artificially increased to determine whether or not the penetration speed could be increased and still maintain an acceptable equivalent circulation density below the fracture gradient. In this example of real time well data, one could easily increase the penetration rate by 50% and remain well below the fracture gradient.

In addition to the potential time savings, other potential costs associated with drilling can be optimized. Some of these include, among others: Changes in the formulation of the muds with both aggregates of the product and the selection of real systems based on historical / reference data, changes in the formulation of the muds based on neural networks or other artificial intelligence techniques related to recommendations for real-time neural network for lubricity, torsion and drag issues, lost circulation problems, maintenance of lost circulation materials, changes in operating procedures, optimization of the trephine selection, and trepan life, coupling of weight in the trephine, penetration speed, and pumping speed, sediment diameter and contamination of low gravity solids and treatment.

Therefore, an embodiment of a method presented in FIG. 7 would involve the collection of real-time drilling pressure data from a drilling rig sensor 701, acquiring data of equivalent circulation density modeled for said drilling rig 702, calculating the standard deviation of the differences in data from said drilling pressure.

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'· NP' real-time drilling and said equivalent circulation density modeled 703, and calculating a set of maximum predictable equivalent circulation density data for the drilling process based on the calculated deviation 704 and determining the penetration speed of the drilling platform based on the maximum tolerable equivalent circulation density data of the 704 drilling process.

Most real-time data efforts focus on risk management, through the prevention and mitigation of errors that cost the operator money. Instead, the present invention works by capitalizing on an unexploited opportunity. By using previously existing sources of information, the invention combines them in a novel and non-obvious use of the standard deviation between actual and modeled data. This technology can also be used as a training tool and post-well control tool.

It should be noted that the drilling optimization system 600 is illustrated and explained herein as having several modules and units that perform particular functions and interact with each other. It should be understood that these modules and units are simply segregated on the basis of their function for the purposes of the description and represent computer hardware and / or executable software code that is stored in a computer-readable medium for execution in a suitable computer hardware. The various functions of different modules and units can be combined or segregated as hardware and / or software stored in a computer-readable medium as previously as modules in any way, and can be used separately or in combination.

While various embodiments according to the present invention have been shown and described, it is understood that the invention is not limited to

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same. The present invention can be changed, modified and also applied by the person skilled in the art. Therefore, the present invention is not limited to the detail shown below and described previously, but also includes all changes and modifications.