The following article is written by Alan Juárez Reyes and Vicente Josafat Sandoval Gutiérrez.
Perla Velasco translator.
In the southeastern region of Mexico, the development of oil fields is increasingly facing greater challenges. Currently, deeper reservoirs with complex geological settings and high pressure-temperature conditions have been discovered. One such case is Field A, located 17km from Comalcalco, Tabasco. This field is characterized by a complex geological history as a result of various tectonic-sedimentary events that gave rise to the sedimentary deposit which today make up its geological column.
The field’s geological conditions have led to deviations in drilling operations, prompting the execution of a thorough analysis by each specialty involved in the project, resulting in synergies across the entire multidisciplinary group.
This following article will address the challenges of drilling deep wells in Field A in the Isthmus Basin, presented during planning and execution, as well as improvement actions implemented that have allowed Opex Perforadora to optimize drilling times and, in turn, reduce delivery times to production.
Field A is characterized by the presence of salt structures with upward thrust, which are defined as precursors to the origin of sedimentary basin formation.
The current development of the field consists of four producing wells and three in operation. During the drilling process, these wells experienced specific particularities related to their geographical location in the field, which required a more extensive multidisciplinary analysis aimed at better understanding its geological environment.
With the support of Opex Perforadora's geology, geophysics, and geomechanics departments, a geological characterization was conducted by zones to determine the most critical drilling risks as well as the plans to mitigate them.
Field A’s Historical Background
Due to the specific challenges encountered during well drilling, particularly in relation to high-pressure sands, a decision was made to partition the field into two distinct blocks, (Block 1 and Block 2). This division became necessary due to the influence of a regional fault on the positioning of the sands.
Figure 1. Structural configuration of Field A in JSK divided by blocks.
Optimization in the design of Field A according to the risks encountered during drilling:
Throughout the development of Field A, numerous events occurred during drilling, including partial loss of circulation, influx, tabular collapses, gasification, and entrapments.
The most prominent risks in Field A include the presence of sandy intercalations with high pressure and a lower fracture gradient in western zone of the field. This led to the installation of a contingency 11¾-inch liner to continue drilling the high-pressure zone.
The current design of Field A includes five Tubing-Retrievable (TR) packer installations and one contingency (Figure 2). This is a robust mechanical arrangement that, based on the information obtained from the current wells drilled in the field, is considered to be optimizable.
Figure 2. Geomechanical Model and Key Drilling Risks of Field A
Optimization 1 (Eliminate 16-Inch TR Placement)
The placement of the 16-inch TR aims to isolate the sequence of producing depressed sands from the tertiary; nevertheless, well No. 3 was drilled in the northeast zone of Field A. Due to mechanical limitations of the drilling equipment, the placement of the 16-inch TR was programmed without fully covering the depressed sands section.
The remaining section of these sands was isolated with the placement of the 133/8-inch" TR. During drilling, only two intervals showed low pore pressure gradients (0.33 and 0.84 g/cm3), which were drilled with mud densities (1.44 g/cm3) using high-performance bridging materials. By doing this, the risk of severe circulation losses and differential sticking was reduced, leading to the determination that it is feasible to eliminate the placement of the 16-inch TR in this area of the field.
Optimization 2 (Eliminate 11¾-inch Contingency Liner)
The most critical area of Field A is located in the over-pressured sand sequence of the Miocene. This area is influenced by its position within the field. For Block 1, with an eastern direction, one can appreciate in wells 1A, 1, and 2 that the sand section is located at approximately ±4,000 mv, and at this depth, the fracture gradient is high (2.08 g/cm³).
Block 2, with a western direction, has a tendency to structurally uplift due to the influence of the regional fault. The sands are found at a shallower depth level than in Block 1. In well 6 ST, the high-pressure sand section was encountered at approximately ±3,750 mv (Figure 3), where an influx occurred, leading to a sidetrack and subsequently setting a contingency liner before the high-pressure zone.
Figure 3. Pressure Profile of Wells 1A, 1, 2, and 6 ST.
Optimization 3 (Casing Set 9 ⅝-inch TR)
The placement of the 9⅝-inch TR aims to cover the abnormal pressure zone that starts in the Miocene and extends up to the electric log marker at the top of the Upper Cretaceous Agua Nueva (KSAN) formation. However, based on the information obtained during the drilling of well 1 in Field A, it was observed that the placement of this TR within the Upper Cretaceous San Felipe (KSSF) formation, solely to isolate the abnormal pressure zone accompanied by the presence of the Upper Cretaceous Méndez (KSM) shale formation, provided the sufficient gradient to drill through the reservoir section. Additionally, it increased the rate of penetration and optimized operational times when drilling with an 8½-inch drill bit.
Optimization 4 (Increase of Rate of Penetration in 8½-inch Stage)
During the drilling of well 2, one of the events with the greatest impact on drilling times was the low rate of penetration in the 8½-inch stage due to the presence of flint in KSAN and KM, indicated by red boxes (Figure 4). This led to additional trips for drill bit changes.
Given the success achieved in drilling the 8½-inch stage in well 2, the application of the downhole motor was replicated in the bottom hole assembly perforation design for well 6. This allowed the reduction of trips to change the drill bit from nine to two, resulting in the longest recorded drilling in the Mesozoic using a PDC 713 drill bit (Record: 1077 m cut, ROP of 4 m/hr, wear of 3-4-RO-S-X-I -CT/HC-TD).
Figure 4. Stratigraphic Correlation of Wells 1, 6 ST, and 2.
Optimization 5 (Drilling of 8½-inch and 5⅝-inch stages in a single run)
During the drilling of the last two stages (8½ inches and 5⅝ inches) in the Upper Cretaceous and Upper Jurassic of well 1, similar drilling mud densities were used. However, since competent formations without indications of lost circulation were observed while drilling the Cretaceous section in well 2, the decision was made to drill both stages (8 ½ inches and 5⅝ inches) in a single run, replicating this good practice in the upcoming well design for the development of Field A.
In Field A, the geological characterization allowed for the delimitation of the critical zone of high-pressure sand in the Miocene, identifying seismic reflectors and electric logs as control points. Consequently, in well 6 ST, following the influx event, the contingency liner of 11¾ inches was successfully set prior to entering this section. This prevented the recurrence of the influx, allowing drilling to continue according to the original program.
By identifying the influx zone in well 1B and with the collaboration of the entire geoscience team, the extent of high-pressure sand was determined. This led to planning a directional trajectory in well 8, which enabled us to avoid the influx zone and achieve successful drilling. This approach prevented deviations in operations and optimized operation times by up to 50 days.
The continuous evaluation of drilling events and information from correlation wells within Field A allowed Opex Perforadora to identify areas of opportunity and operational risks. These areas have been mitigated through the implementation of safe operational practices and design reengineering to optimize costs and operational times. This translated into the early incorporation of wells into production.
This text is an excerpt from the paper, Challenges and Deep Well Drilling Challenges in Field A in the Salina del Istmo Basin, authored by Alan Juárez Reyes and Vicente Josafat Sandoval Gutiérrez, which was presented at the 2023 edition of the Mexican Petroleum Congress. The full article in Spanish can be consulted here.
Alan Juárez Reyes is a petroleum engineer and graduated from the National Polytechnic Institute. He currently works as a drilling design engineer at Opex Perforadora. The engineer Juárez Reyes began his professional career in 2012 at the Weatherford company as an assistant company man in the Burgos basin and Aceite Terciario del Golfo. Subsequently, he joined Weatherford as a drilling and completion design engineer in mature Tertiary-South fields. In 2014 he joined PEMEX Exploration and Production as a well engineer in Reforma, Chiapas. At PEMEX he also held other positions such as operations coordinator in HPHT wells in Litoral de Tabasco, design engineer and operation support at PEMEX Perforación y Servicios, drilling design engineer in the Well Intervention Engineering Management of Exploitation and in the Management of Execution and Monitoring of Development Wells.
Vicente Josafat Sandoval Gutiérrez is a geomechanic in the Management of Execution and Monitoring of Development Wells in PEMEX. Sandoval Gutiérrez is a petroleum engineer with a specialty in Geomechanics. He has participated in various projects developing 1D Geomechanical models within the VCDSE multidisciplinary teams to assess mud densities and casing depth of settlement, as well as performing hole stability analysis and geopressure updating in real time.