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Petroleum & Petrochemical Engineering Journal Research Article 15 min read

Offset Wells Data Analysis and Thermal Simulations Improve the Performance of Drilling HPHT Well

Ivan R, Halafawi M* and Avram L*
* Corresponding author
ISSN: 2578-4846  10.23880/ppej-16000298  Received: February 11, 2022  Published: March 18, 2022
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 53 references
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Keywords
HPHT wells Offset data Field studies Thermal simulation
Abstract

To drill new HPHT development wells safely, an exact estimate of their stability is essential. Analyzing previously drilled offset wells can assist in this determination, eliminating any stratigraphic column issues and saving nonproductive time. The challenges found with offset wellbores, their consequences on well design, possible remedies, and preventative measures are discussed in this paper. It examines drilling data from offset wells in order to discover, diagnose, and treat serious issues. Furthermore, thermal simulation was done in order to study the temperature distribution of the wellbore, annuli and fluids during drilling, tripping, circulation, logging, casing and cementing in HPHT zone

Introduction

HPHT wells refers to high pressure and high temperature boreholes. They are an inescapable byproduct of the world’s never-ending hunt for new hydrocarbon resources. The high pressures and temperatures are bigger challenges during designing, drilling, and doing operations in these wells. When constructing such wells, each string design influences the design of other strings due to the unusual encountered stresses, unlike the traditional well design, such as annular pressure accumulation connect numerous strings. HPHT circumstances result in a variety of non-standard load situations, necessitating the use of non-standard fluids and materials, advanced design techniques, and innovative processes. The design of these wells frequently need material or equipment which are difficult to meet at the current technology [1].

In order to define HPHT wells, a common definition of these wells has not been developed; in any event, most administrators regard a well with a formation temperature in excess of 300 oF and a surface closing pressure more than 10000 psi to be an HPHT application [2]. Wells with layer temperatures above 425 oF and pressures over 15000 psi are commonly referred to as ultra-HPHT or extreme-HPHT (X-HPHT) wells [3]. The UK Heath and Security Executive has recommended that for an application to be classified as HPHT, the undistributed bottomhole temperature must exceed 300 oF and have a formation pressure gradient in excess of 0.8 psi/ft or require the utilization of controlling equipment rating in excess of 10000 psi working pressure [4].

It is critical to note that bottomhole temperature and zone pressure are critical. Borehole temperature and formation pressure are not, in and of themselves, indicators of HPHT conditions. The geothermal change is a third factor that will be used to identify situations in which hot issues demand special attention. Warm impacts became genuine enough to need remarkable thought amongst planning after a geothermal gradient of 0.014 oF/ft [1].

In this paper, we review the HPHT circumstances that are considered in plan all through the world. In this portion, we endeavor to characterize the term HPHT as well as distinguish the worldwide dissemination of HPHT indications. The study examines strategies and methods for assessing temperature and pressure, which are clearly basic within the plan of HPHT wells. The effect of HPHT on the characteristics and execution of liquids and materials, as well as non-standard stresses put on wells, are investigated. The operational results of HPHT circumstances, especially as they relate to well control, are inspected.

Previous Studies

Drilling in HPHT fields and regions is highly difficult and required a lot of circumstances, technologies, strategies and plans in order to do the trajectory and reach target safely and cost effectively. There are several authors who studied those area and cover main researches. Table 1 shows a survey study of published researches regarding the HPHT wells’ problems and their solutions, pressure and temperature estimation methods, thermal analysis, and wellhead movement.

Author (s)Publication YearStudy/ or Technique Developed
HP/HT Wells Problems and Pressure Estimation Methods
Maury and Idelovici [5]1995Studying the effect of transient thermal regime, which comprises
alternating cooling and heating of the wellbore, and causes a
loss of well stability while drilling under HP/HT circumstances.
Kelley, et al. [6], Sweatman, et al. [7],
and Webb, et al. [8]		2001Presenting HP/HT well pore pressure integrity and treatments
to avoid problems
Skomedal, et al. [9]2002A study of the reservoir rock’s mechanical behavior when
uncovered to varieties in stress and formation pressure
Swarbick [10]2002The limits of porosity-based prediction tools and popular ways
of predicting formation pressure
Shaughnessy, et al. [11]2003Issues involved with ultradeep HP/HT wells and their solutions
Esmersoy and Mallick [12]2004A novel approach/ or technique for predicting pressures ahead
of the bit using vertical seismic profile (VSP)
Wellbore thermal problem and temperature estimation methods
Marshal and Bentsen [13] Hasan and
Kabir [14]		1982
2002		Studying typical thermal characteristics of formation and
borehole materials.
Prensky [15]1992Geothermal temperature estimation techniques
Sathuvalli, et al. [16]2001Investigating the significant geothermal gradients seen in
offshore oil and gas fields
Beardsmore and Cull [17]2001Errors in the estimate of the geothermal gradient due to
geologic noise
Hasan and Kabir [14]2002Investigating the borehole thermal problem and the numerous
situations that arise during drilling fluid circulation and
formation fluid generation.
Wellbore thermal analysis and measurement techniques
Ramey’s [18]
Raymond [19]
Willhite [20]		1962
1967
1969		Building semi-analytical models for borehole thermal analysis
and predicting injection and production temperatures
Vidick and Acock [21]1991highlighting some of the flaws in some of the flow temperature
measuring methodologies
Impact of High temperatures on material characteristics
Berckenhoff and Wendt [22]2005Examining the impact of high temperatures on material features
such as elastomers and how they affect the system’s sealing
integrity
Brownlee, et al. [23]2005Offering a thorough examination of the industry’s materials
selection techniques for sour HP/HT wells
Nice, et al. [24]2005Discussing the development of a moderate sour benefit,
125-ksi high-strength low-alloy steel study for the Kristin
production casing
The impact of HP/HT circumstances on PVT behavior of reservoir fluids
Fisk and Jamison [25], Oakley, et al.
[26], Zamora, et al. [27]		1989
2000		Examining the impact of high temperatures on mud
characteristics
MacAndrew, et al. [28], Mansour, et
al.[29], Rotmero and Loizzo [30],		1993
1999
2000		Providing research on the loss of cement mechanical properties
under the impact of temperature
Rommetveit and Bjørkevoll [31],
Harris and Osisanya [32].		1997
2005		Building a simulator to forecast the pressure and temperature
dependency of mud density and rheological parameters
Wang and Su [33]2000Presenting a pressure-temperature model for estimating
equivalent static density (ESD) in HPHT circumstances
Danesh [34]2002Doing experiments to demonstrate that increasing water
content enhances the viscosity of formation fluids
Saasen, et al. [35]2002Presenting benefits of cesium formate for the Huldra field in
the North Sea, which had a kick owing to barite sag in the OBM
utilized
Griffith, et al. [36]2004Investigating the use of foamed cement systems to lessen the
influence of temperature
Gozalpour, et al. [37]2005Demonstrating the impact of temperature on the volatility of
heavy elements in HP/HT fluids
Developed thermal loads due to higher temperatures
Handelman [38], Lubinski [39],
Lubinski, et al. [40], Hammerlindl
[41], Sparks [42], Mitchell [43],
Paslay [44], He and Kyl-lingstad [45],
Lea ,et al. [46]		1946, 1951, 1962,
1980, 1984, 1986,
1994, 1995, 1995		Addressing the problem of buckling in restricted tubulars
caused by high thermal loads
Handelman [38], Lubinski [39],
Lubinski, et al. [40], Hammerlindl
[41], Sparks [42]		1946, 1951, 1962,
1984		Presenting the equations and theory needed to calculate
effective forces for buckling and post-buckling analyses
Suryanarayana and McCann [47]1995Presenting buckling theory and experimental findings
ISO 13679 [48]2002Recommendation of using premium connections for HP/HT
wells designing utilizing severe testing techniques.
Bradley, et al. [49], Carcagno [50]2005Addressing the issue of increased thermal loads created by
higher temperatures
Wellhead movement (WHM) and annular pressure buildup APB
Adams [51]1991Provides the formulas for calculating WHM and thermal stresses
resulted from the elastic spring model’s thermal expansion of
the strings.
Halal and Mitchell [52]1993Highlighting the multistring casing design, which addresses the
elastic response of the casing system.
Samuel and Gonzales [53]1999Describing the optimizing of multi-string casing design for
annuli fluid expansion and wellhead increase

Table 1: Literature review study of HPHT wells.

Field Case Study, Results and Discussion

Field Description

A gas field located in Arab Gulf is classified as HPHT field because of appearing pressure in excess of 10000 psi and temperature over 300 oF during drilling its stratigraphic column (Figure 1). The drilling program is issued to drill 3 wells among between the previous drilled wells. The wells are proposed as a vertical S-shape well with Pre-Khuff as primary and Khuff-C as secondary objective in the gas field. Also, Offset and planned wells map is shown in Figure 2.The well is designed as a special well due depleted pressures in Khuff-C and high pressure in Pre-Khuff. The well is designed as a S-shape because of the surface location issues.

Otherwise, Hydrocarbon potential are:

  1. Zones of primary hydrocarbon potential Pre-Khuff.
  2. Other Known accumulations of hydrocarbons include: • Oil in carbonates of the Arab-D Reservoir. • Gas in Khuff Reservoir. • Shallow gas is not expected in this location.

Furthermore, the pressure and temperature profiles of this region are plotted in Figures 3 and 4. Additionally, the future planned selected mud weights are constructed in Figure 3. So as to improve the future drilling performance, offset data analysis is done for previously drilled offset wells.

Offset Data Analysis

For the production section - 5 7/8 inch hole with 4 1/2 inch liner, 5 7/8 inch hole where the problem of HPHT appears, is drilled with the performance BHA bottom assembly from 4204 meters to +/- 4505 meters MD / 4411 m TVD (60 m - 200 ft in layer) with KCl type drilling mud polymers with ideal density 1553 kg/m3 (97 pcf). A volume of cleaning fluid is circulated before the introduction of the casing. Investigations (mud logging and wireline logging) are done for this section. Potential hazards and information from neighboring or similar wells are also detected. Based on information from offset wells, the following risks are considered relevant for this section (Table 2 & Figure 5)

  • Slow ROP and bit wear due to abrasive Unay and Jauf formations.
  • Possible sloughing shale and tight spots in Tawil formation.
  • Possible high pressure in Unay and Jauf reservoirs.
  • Hole washout in Jauf formation Based on offset data analysis, the drilling parameters are optimized and selected for the 5 7/8 inch borehole section until the 4-1 / 2 inch liner is landed at 4505 meters MD / 4411 m TVD, as follows:
  • WOB: 15 – 22 klbs
  • Flow Rate: 160 – 200 gpm
  • RPM: 60 – 90 Expected ROP: 15 – 40 ft/hr Due to the overpressure in the Jauf layer, a risk of differential clamping is estimated. In this regard, it is necessary to minimize the time to make a connection or any time in which the gasket is stationary. Additionally, the optimum mud weights are selected and plotted in Figure 3. Finally, the planned depth-time graph is constructed and shown in Figure 6. The required days for drilling the next HPHT well are 71 days of drilling, conditioning, logging, casing, cementing, and completion.
Figure 1: Geological column of area.
Click to enlarge
Figure 1: Geological column of area.
Figure 2: The well is designed as a special well due depleted pressures in Khuff-C and high pressure in Pre-Khuff. The well is designed as a S-shape because of the surface location issues.
Click to enlarge
Figure 2: The well is designed as a special well due depleted pressures in Khuff-C and high pressure in Pre-Khuff. The well is designed as a S-shape because of the surface location issues.
Figure 3: So as to improve the future drilling performance, offset data analysis is done for previously drilled offset wells.
Click to enlarge
Figure 3: So as to improve the future drilling performance, offset data analysis is done for previously drilled offset wells.
Figure 4: Mud density and temperature distribution for case #1.
Click to enlarge
Figure 4: Mud density and temperature distribution for case #1.
Offset Well No.Mud weight (pcf)Risk / Event / Prevention / Mitigation
1881. Drilled interval: 13,000’ to 15,135’ starting from 73 till 100 pcf.
2. Well flow at 14,944’ (TWIL), killed with 88 pcf.
2941. Drilled interval: 12,040’ (KHUFF B base) to 13,775’.
2. Unable to complete coring due to abrasive sands in UNNZC.
3891. Drilled interval: 12,560’to 14,052’ starting from 74 till 89 pcf.
2. Well flow at 12,865 killed with 89 pcf.
4921. Drilled interval: 12,560 (JAUF TOP) to 14,550’ (450’ below JAUF).
5941. Drilled interval: 12,438’ (KHUFF-B top) to 14,597’ (TAWIL).
697Drilled 5-7/8” hole from 13,552’ to well TD at 14,481’ (180’ into TWIL).
Ran and cemented 4-1/2” liner.
1. Drilled interval: 13,552’ (450’ into KFDA) to 14,052’ (180’ intoTWIL).
768-74/941. Drilled interval: 13,937’ (KFCC) to 5,807’ MD / 14,989’ (200into TAWIL).
2. Well flow at 14,183’ MD / 13,380’ TVD (KFC-10), killed with 74 pcf mud.
3. Reaming BHA stuck at bottom.
4. MDT on TLC got stuck at 15,369’ MD /14,520 TVD (JAUF).
8961. Drilled interval: 13,435’ to 14,350’ (TWIL).
2. String stuck at 14,350’ (TWIL).
9951. Drilled interval: 13,885’ (UNZA) to 14,350’ (TWIL).
2. Wireline held up on 2 occasions at 14,48 (JAUF) and 14,806 (TWIL), performed
logging on TLC.

Table 2: Offset wells data analysis.

Figure 5: ROP data analysis.
Click to enlarge
Figure 5: ROP data analysis.
Figure 6: Depth-time curve for future wells.
Click to enlarge
Figure 6: Depth-time curve for future wells.

Simulations Results and Analysis

A simulation study is done using landmark software in order to show the effect of HPHT on future wells. For the production section - 5 7/8 inch wellbore with 4 1/2 inch liner, HPHT appears. The temperature simulation and design would be done and performed in this section with Landmark software. Figure 7-9 show the geothermal gradient and temperature of the drill string and at the annular space. It is noted that the temperature of the drill string also increases at the annular space, and reaches the geothermal gradient despite the cooling caused by the mud. Simulations and modeling studies were performed for HPHT well pressures and dynamic conditions.

The entire circulation system has been optimized to determine and predict pressure losses, pump flow rates, flow pressure, pressure loss distribution, ECD and circulation pressure. During the modeling, the effect of temperature, change operations, cuttings loading and DFG hydraulic model was taken into account. Figures 10-15 shows the simulation results including various effects such as temperature, change operations, cuttings loading and DFG. It found that the HT increases the pressure distribution and losses in the hydraulic system during drilling HPHT section than normal case (Figures 11 & 12). Further, the variations of ECD during drilling operation causing swab and surge problems are appeared in Figure 12. Now, we can overcome the future surge and swab problem during drilling this zone.

Additionally, the HT induces the increasing of annulus and string pressure during circulation making them moving towards fracture pressure and super passing it (Figure 14). However, this effect does not exist in case of lower temperature or without taking the effect of temperature (Figure 15). Therefore, HPHT well can effectively be drilled based on offset data analysis and simulation so that the best drilling parameters can be optimized and selected carefully.

Figure 7: Well Profile.
Click to enlarge
Figure 7: Well Profile.
Figure 8: Well schematic.
Click to enlarge
Figure 8: Well schematic.
Figure 9: Temperature variation in the wellbore with depth.
Click to enlarge
Figure 9: Temperature variation in the wellbore with depth.
Figure 10: Pressure losses variation with flow rates including temperature effect.
Click to enlarge
Figure 10: Pressure losses variation with flow rates including temperature effect.
Figure 11: Pressure losses variation with flow rates including DFG Model.
Click to enlarge
Figure 11: Pressure losses variation with flow rates including DFG Model.

[equation]

Figure 12: Now, we can overcome the future surge and swab problem during drilling this zone.
Click to enlarge
Figure 12: Now, we can overcome the future surge and swab problem during drilling this zone.
Figure 13: Circulation pressure per run for drilling HPHT section including the effect of HT and DFG model.
Click to enlarge
Figure 13: Circulation pressure per run for drilling HPHT section including the effect of HT and DFG model.
Figure 14: Circulation pressure for drilling HPHT section including temperature effect and DFG model.
Click to enlarge
Figure 14: Circulation pressure for drilling HPHT section including temperature effect and DFG model.
Figure 15: Circulation pressure for drilling HPHT section without temperature effect.
Click to enlarge
Figure 15: Circulation pressure for drilling HPHT section without temperature effect.
Figure 16: Fluid temperature during drilling operations.
Click to enlarge
Figure 16: Fluid temperature during drilling operations.

Thermal simulation study was also done as shown in Figures 16 through 22 in order to study the temperature distribution in the wellbore and around it. During drilling operations, fluid temperature increases. The more period of the operation, the higher fluid temperature acquires (Figure 16). The same situation repeats for the wellbore to be drilled in HPHT section (Figure 17).

This is due to increasing the geothermal temperature with depth during drilling as seen in Figure 18. As a result of that, all the wellbore including boreholes, casings, pipes, annuli, cementing, equipment, strings and devices landed or will be landed would be subjected to be heated during drilling those zones of HPHT (Figures 19-21). Thus, it is recommend to be careful with all material landed if they are suitable or not).

Finally, the required ECD during various operations is shown in Figure 22. It appeared that there are some shallower depths/ zones would be subjected to ECD problems but those would be cased during drilling HPHT section. Consequently, there would not be problems with those areas.

Figure 17: Wellbore temperature during drilling operations.
Click to enlarge
Figure 17: Wellbore temperature during drilling operations.
Figure 18: As a result of that, all the wellbore including boreholes, casings, pipes, annuli, cementing, equipment, strings and devices landed or will be landed would be subjected to be heated during drilling those zones of HPHT (Figures 19-21). Thus, it is recommend to be careful with all material landed if they are suitable or not).
Click to enlarge
Figure 18: As a result of that, all the wellbore including boreholes, casings, pipes, annuli, cementing, equipment, strings and devices landed or will be landed would be subjected to be heated during drilling those zones of HPHT (Figures 19-21). Thus, it is recommend to be careful with all material landed if they are suitable or not).

Conclusion and Recommendations

HPHT well is a big a challenge, and needs several studies and advanced technologies. In our case, the HPHT zone has a little bit pressure of less than 10000 psi but the temperature of more than 300 oF. However, this zone can be considered as an HPHT region based on the definitions previously presented. Although our simulations and study contain a lot of details regarding HPHT well, the conclusions will include the only part presented in this paper, which is about offset data analysis, and simulation with landmark to show the effect of HPHT on circulation system, as follows:

  1. HPHT zone changes most of the drilling parameters during operations.
  2. HT has a great effect on pressures’ profiles and fluids composition.
  3. Offset data analysis plays a great role in future development plans.
  4. Thermal simulation is a key-element to study temperature distribution in HPHT wells.
  5. HPHT increases the swab and surge problems.
  6. It is recommended to be careful for all material used in HPHT well if there are suitable or not.
  7. HPHT Technologies, materials, fluids and standards are often your requirements without thinking.
  8. Wellhead movement (WHM) and annular pressure buildup (APB) will be a challenge due to annuli pressurizing and multistring interaction.

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@article{ivan2022,
  title   = {Offset Wells Data Analysis and Thermal Simulations Improve the Performance of Drilling HPHT Well},
  author  = {Ivan R, Halafawi M* and Avram L},
  journal = {Petroleum & Petrochemical Engineering Journal},
  year    = {2022},
  volume  = {6},
  number  = {1},
  doi     = {10.23880/ppej-16000298}
}
Ivan R, Halafawi M* and Avram L (2022). Offset Wells Data Analysis and Thermal Simulations Improve the Performance of Drilling HPHT Well. Petroleum & Petrochemical Engineering Journal, 6(1). https://doi.org/10.23880/ppej-16000298
TY  - JOUR
TI  - Offset Wells Data Analysis and Thermal Simulations Improve the Performance of Drilling HPHT Well
AU  - Ivan R, Halafawi M* and Avram L
JO  - Petroleum & Petrochemical Engineering Journal
PY  - 2022
VL  - 6
IS  - 1
DO  - 10.23880/ppej-16000298
ER  -