Evaluation of Mud Weight Using Safe Mud Window Concept Based on Well Log Data: A Case Study of Well OP-002 in the North Sumatra Basin Area, Indonesia

In the drilling operation of well OP-002 which is located in the North Sumatra Basin at a depth interval of 2887 - 3186 m occurred partial loss, and caving at a depth interval of 500 - 1650 m, where the drilling problem is caused by the use of inappropriate mud weight. Safe mud window analysis is carried out by processing well log data to build PPFG (Pore Pressure Fracture Gradient) and 1D Geomechanics model using several calculation methods. Furthermore, the results of the calculation of pore pressure and fracture gradient are validated with well test data from the well OP-002, so the safe mud window can be determined, and can be used as a basis in the analysis of the drilling problems that occur. The optimum mud weight can minimize wellbore instability, with a limit value that must be greater than the collapse pressure, but not exceeding the minimum insitu stress limit. From the results of the mud safe window analysis, it can be concluded that at a depth interval of 500 - 1650 m caving occurs, because the density value used is smaller than the shear failure gradient, and at a depth interval of 1619 - 2829 m, the density value used is greater than Shmin. To overcome this problem, a mud wight with a safe mud window concept is recommended, namely the selection of the optimum mud weight to be used must be greater than the pore pressure and shear failure gradient and does not exceed the minimum horizontal stress and fracture gradient values.

Subsea Re-Abandonment Strategies for High-Risk Wells to Minimize Leakage Risk in a Depleted Field for CO2 Storage

CO2 storage in a depleted field comes with the risk that is associated with wells integrity which is often defined as the ability to contain fluids with minimum to nil leakage throughout the project lifecycle. The targeted CO2 storage reservoir in offshore Malaysia has existing abandoned exploration/appraisal, and development wells. With a view of developing such CO2 storage sites, it is vital to maintain the integrity of the abandoned wells. High-risk characterized wells need to be analyzed and remedial action plan to be defined by understanding the complexity involved in restoring the integrity. This will safeguard CO2 containment for decades. Abandoned exploration/appraisal wells in the identified field are >40 years old and were not designed to withstand CO2 corrosion environment. Downhole temperature and pressure conditions may have further degraded the wellbore material strength elevating corrosion susceptibility. The reservoir simulation predicts that the CO2 plume will reach to these abandoned wells during the initial phase of total injection period. Single well was selected to assess the loss of containment through the composite structure along the wellbore and to determine the complexity in resorting the well integrity. CO2 leakage rates through all possible pathways were estimated based on numerical models and the well is characterized for its risk. For unacceptable leakage risk, the abandoned well needs to be re-entered to restore the performance of barriers. Minimum plug setting depth (MPSD) and caprock restoration considers original reservoir pressure(3450psia) anticipating the pressure buildup upon CO2 injection and is derived based on fracture gradient and maximum horizontal stress. This paper elaborates unique challenges associated with locating abandoned wells that are submerged below seabed. Top and side re-entry strategies are discussed to overcome challenges. Based on past abandonment scheme, leakage rate modeling calculates estimated leakage rate of ~460SCFD at higher differential pressure of around 3036psia at shallowest barrier and ~15SCFD for differential pressure of 1518psia at deepest barrier. Sensitivity analysis has been carried out for critical barrier parameters (cement permeability, cracks, fractures) to the containment ability and improving understanding of quality of barriers, uncertainties, and complexities for CO2 leakage risk. The paper proposes two(2) minimum plug setting depths (3550ft & 3750ft) derived based on fracture gradient and maximum horizontal stress. Perforate-wash-cement (PWC) and section milling were compared for operational efficiencies to achieve caprock restoration. for MPSD out strategic options to restore well integrity by remediating casing/cement barriers at by performing best fit abandonment technique to contain CO2 in the reservoir. Well integrity risk is assessed for existing plugged and abandoned (P&A) wells in a carbon storage site. Optimized remedial actions are proposed. Quantification of all the uncertainties are resolved that may affect long-term security of CO2 storage site.

Impact of Static and Dynamic Wellbore Strengthening on Well Planning in Petroleum Development Oman

Formation Integrity Tests (FIT) or Leak-Off Tests (LOT) are common techniques to reduce the uncertainty in Fracture Gradient (FG) prediction for well planning, but are usually performed at the casing shoe. This article will discuss the first examples of open-hole LOT and FIT in Petroleum Development Oman (PDO), targeting depleted formations in water injector or oil producer wells. The data was used to justify continued drilling of slim wells with two casing strings, where otherwise three casing strings would be required, provided dynamic wellbore strengthening is applied. In addition, the concept of static wellbore strengthening was also trialed for the first time in Oman, using the hesitation squeeze testing procedure, by which the effective leak-off pressure was incrementally increased to match the maximum ECD required for cementing.

Mitigating Well Construction Challenges of a Caspian Deepwater Exploratory Well: A Cementing Perspective

BP returned to Caspian deepwater exploratory drilling in 2019. The exploration well was drilled on the Shafag-Asiman structure in water depths greater than 2,000 ft. Well challenges included high shallow water flow (SWF) risk with multiple re-spuds on the nearest offset, lost circulation due to complex wellbore geometry combined with a narrow pore and fracture gradient window, and uncertainty in pore pressure prediction in abnormally pressured formations with a new depositional model. In addition, a well total depth more than 23,000 ft, eight string casing design and bottom-hole pressures greater than 20,000 psi presented a truly modern-day challenge to well integrity. A six-month planning phase for the cementing basis of design concluded by delivering slurry designs capable of combating SWF, qualified by variable-speed rotational gel strength measurement. Engineered lost circulation with selective placement of wellbore strengthening materials in combination with cement and mechanical barriers to provide isolation and integrity for the life of the well. Exhaustive pilot testing to account for changes required a cement design based on pore pressure variation and comprehensive modeling for hydraulics, centralizer placement, and mud displacement. This was complemented by a custom centralizer testing process specifically designed to simulate forces exerted in wells with similar complexity. Long-term effects on cement were evaluated, not only for placement but also for future operations including pressure and temperature cycles during wellbore construction or abandonment.

Wellbore Strengthening Design Criteria and Enhanced Fracture Gradient for Widening Stable Mud Weight Window and Enabling Safe and Efficient Drilling in Depleted Reservoirs

Drilling in permeable formations, especially depleted reservoirs, can particularly benefit from simultaneous wellbore shielding and strengthening functionalities of drilling mud compounds. The ability to generate simultaneous wellbore shielding and strengthening in reservoirs has potential to widen stable mud weight windows to drill such reservoirs without the need to switch from wellbore strengthening compound to wellbore shielding compound, and vice-versa. Wellbore shielding and strengthening experiments were conducted on three outcrop sandstones with three mud compounds. The wellbore shielding stage was conducted by increasing the confining and borehole pressures in 4-5 steps until both reached target pressures. CT scan images demonstrate consistency of the filtration rates with observed CT scanned mud cakes which are dependent on the sandstone pore size and mud compound particle size distributions. In wellbore strengthening stage, the borehole pressure was increased until fracture was initiated, which was detected via borehole pressure trend and CT scan imaging. The fractures generated were observed to be plugged by mud filter solids which are visible in the CT scan images. The extent of observed fracture solid plugging varies with rock elastic properties, fracture width and mud compound particle size distribution. Based on the laboratory test data, fracture gradient enhancement concept was developed for the mud compounds. In addition, the data obtained and observations from the tests were used to develop optimal empirical design criteria and guidelines to achieve dual wellbore strengthening and shielding performance of the mud compounds. The design criteria were validated on a well which was treated with one of the mud compounds based on its mud loss events during drilling and running casing.

Unconventional Single Slurry Solution for ERD Wells with Depleted Formations

Tailoring slurry designs using amorphous liquid silica base has been a success for Cementing Extended Reach Drilling (ERD) wells in Brunei in development fields. The use of this unconventional slurry density and design has helped to achieve the necessary top of cement and required zonal isolation for the production string of these wells. Cementing across depleted formations has been a challenge for the drilling sector within the oil industry. Isolation of production zones with competent cement slurries has become a necessity in fields, especially where a low Equivalent Circulating Density(ECD) during the cementing operation is required to achieve the desired top of cement in low fracture gradient formations. For Brunei offshore operations a novel approach has been proposed that uses an amorphous liquid silica-based slurry system to design a new 14 ppg lightweight cement slurry. The slurry properties were tailored to eliminate the need for a dual slurry system. Planning, execution, and post-operation evaluation methods have been developed for this new design. Extensive laboratory testing has been performed for the 14 ppg extended slurry which includes basic slurry testing as well as more advanced evaluations such as a full mechanical properties study and finite element analysis that was used compared to conventional slurry designs. Various optimizations were done for the slurry design to overcome mixability challenges and deployment using a conventional offshore liquid injection system or by premixing the water with liquid additives on a mixing tank or rig pits. To validate this technology, a field trial was performed at the rig site where a production liner for an extended reach well was cemented and subsequently evaluated using cement evaluation logging tools. The first Brunei offshore trial operation, executed in Q2 2020, was a 4.5-in. production liner where 16.5 m3 of a 14ppg novel slurry design was mixed, pumped and successfully placed within the annulus. Since the initial trial, a total of 8 jobs have been executed successfully in Brunei, with a few more wells identified as candidates for this solution. The paper provides laboratory testing details, hydraulic simulation validations along with job execution and post-operation cement evaluation.

Overcoming Lost Circulation Risks in Low Fracture Gradient Formations with a New Tailored Spacer System

In certain regions of oil and gas operations, lost circulation is a common occurrence, especially when a majority of the openhole exposed during primary cementing is carbonate-based formations. This can lead to lost circulation risks in most applications. To overcome lost circulation risks during primary cementing, a new tailored spacer system shows to improve the cement placement success. The manuscript discusses the quality assurance and performance testing with field cases demonstrating the value contributions of the spacer for achieving zonal isolation requirements as well as the top of cement objectives. The work efforts presented shows a spacer meeting and sometimes showing incremental wellbore strengthening in comparison to the published literature for existing available spacers used to overcome similar lost circulation risks.

Pore pressure prediction in Niger Delta high pressure, high temperature (HP/HT) domains using well logs and 3D seismic data: a case study of X-field, onshore Niger Delta

Few wells targeting high temperature, high pressure intervals in most tertiary sedimentary basins have achieved their objective in terms of technicalities and cost. Since most shallow targets have been drilled, exploration focus is drifting into deeper plays both onshore and in deep offshore areas. To ensure safe and economic drilling campaigns, pore pressure prediction methodologies used in the region needs to be improved. The research aims at generating and testing a modification of Eaton’s equation fit for high temperature, high pressure intervals on a field. The evolution of pore pressure in the field was established from offset well data by making several crossplots, and fracture gradient was computed using Mathew and Kelly’s equation. Eaton’s equation parameters were then calibrated using several wells until a desired field scale result was achieved when compared with information from already drilled intervals i.e., kicks and RFT data. Seismic velocity data resulting from high density, high resolution velocity analysis done to target deep overpressured intervals were then used to predict 1D pore pressure models at six selected prospect locations. Analyses reveal depths shallower than 3800 m TVD/MSL with geothermal gradient 3.0 °C/100 m and pressure gradient less than 1.50sg EMW are affected mainly by undercompaction; depths greater than 3800 m TVD/MSL with geothermal gradient of 4.1 °C/10 m and pressure gradients reaching 1.82–2.12sg EMW are affected by unloading with a narrow drilling margin for the deep highly pressured prospect intervals. Eaton’s n-exponent was modified to 6, and it proved accurate in predicting high overpressure in the first prospect wells drilled.

Analytical Study of Early Kick Detection and Well Control Considerations for Casing while Drilling Technology

Recently, casing while drilling (CwD) technology has been employed to reduce drilling time and expenses. These intelligent drilling technique improved wellbore stability, fracture gradient, and formation damage while reducing exposure time but when a well control issue arises, the differences in wellbore geometries and related volumes compared to regular conventional drilling procedures necessitate a distinct strategy. In this paper, the essential well control parameters were provided for casing while drilling operations, presents simplified method that has been developed to evaluate the maximum kick tolerance (KT) for both conventional and casing while drilling techniques using a mathematical derivation, the narrow annular clearance, in contrast to drilling with a conventional drill string would impair kick detection and handling operations. Furthermore, the large disparity in kick tolerances should be carefully evaluated in order to avoid lost circulation/kick cycles as well as examine and evaluate technical approaches to early kick detection (EKD) studying how they relate to safety, efficiency, and reliability in a variety of common casing while drilling operations. According to preliminary findings, by utilizing casing while drilling technology and compared to identical well was drilled conventionally using drill pipe, the annulus pressure loss (APL) is average 3 times of the conventional drilling technique. Furthermore, kick tolerance is reduced by 50% and maximum allowable well shut-in time reduced by 65% necessitating early kick detection.

Productivity Optimization and Validation of Multistage Fracturing in a Rare Geomechanical Setting with Production Logging

A reservoir with a rare geomechanical setting of higher stresses at shallower depths and vice versa was fractured. The multistage fracture responses were validated using production logging data. Further, production optimization was achieved by understanding the flow profile and geomechanical setting to decide on an optimal flow condition for the wells. An innovative solution-driven approach was identified with production logging playing a key role. Based on the geomechanical model, calculated fracture gradient indicated higher stress in the shallower section and lower stress in deeper intervals. Multistage fracturing was performed. Post fracturing, production logging was carried out in Well A at two different chokes to understand flow behavior in wellbore and correlate with reservoir response. Based on these results, an intermediate choke was selected for production logging in Well B to observe any improvement in flow behavior. An integrated study of geomechanics, fracture performance and production logging resulted in deciding an optimal flow condition for the wells. Results are presented for a two well operation. Production logging results indicated that deeper intervals were producing higher compared to shallower layers, thereby validating the geomechanical model. Also, fissures were encountered during deep stage fractures, indicating potentially high production from reservoir from these stages due to better flow conduit. This was also confirmed from the production logging results. In Well N1, production logging data, in the lower choke, indicated sluggish and unstable flow behavior with the top three stages underperforming. However, at higher choke, a steady and uniform flow was observed. The production logging results were also observed to be in line with the obtained frac-operation parameters on the higher choke. However, an anomaly was observed in the second stage of Well N1, which is estimated to be as a result of fractures closing down due to higher stresses in shallower depths. Based on this, an intermediate choke was selected to flow Well N2 and record production log data to observe and evaluate the flow behavior at a different choke. The flow was still observed to be sluggish and unstable at the intermediate choke. Hence, a final decision was taken based on all the different conclusions to flow the wells at higher choke to maintain optimal frac stage performance and a uniform and steady flow. Rare geomechanical setting of reservoirs presented challenges in accurately characterizing them. The paper recognizes the versatility of the production logging tool in delivering and understanding both reservoir response and wellbore flow conditions. The integration of fracture response with production logging results enabled validation of the reservoir response and provided valuable insights into understanding the flow behavior inside the well, and finally optimizing well productivity.