Managed Pressure Drilling and Underbalanced Drilling Compounded Role in Solving the Exploration and Appraisal Challenges of Biogenetic Gas Resources in the United Arab Emirates -Case Study

Biogenic gas resources have gathered importance recently due to its widespread availability, occurrence at geologically predictable circumstances, and existence at shallow depths. It is estimated that biogenic gas forms more than 20% of the global discovered reserves. However, the exploration and development of these unconventional resources come with numerous drilling and reservoir challenges. This paper showcases a novel approach used in the United Arab Emirates to overcome these challenges using managed pressure and underbalanced drilling. To tackle both reservoir and drilling challenges, a hybrid solution combining Underbalanced (UBD) and Managed Pressure Drilling (MPD) was applied. UBD was used to characterize the reservoir in terms of pressure and productivity index to ultimately enhance productivity by eliminating formation damage. MPD was used next to continue drilling through the problematic zone which had high instability due to the presence of highly sensitive salt, in addition to the presence of high pressure and loss zones. The fit for purpose hybrid application design allowed the operator to immediately switch between UBD and MPD conditions, as the well required with the same equipment. Three of the four targeted formations were in the 8 ½″ hole section, UBD was selected to drill the first reservoir formation which allowed pore pressure verification and avoided using excessive mud weight that was the culprit of many challenges like slow ROP, drilling fluid losses, bit balling, and fracking the formations. UBD has proved that mud weight can be reduced by 20%-30% comparing to conventional drilling. The second formation was a salt formation that has caused previously hole collapse and losses-kicks problems as heavy mud used to drill this salty formation. MPD used successfully drill this section by constant bottom hole pressure and lower mud weight as it was found from analyzing offset wells reports that hole collapse occurred at connections and pump off events. Constant Bottom Hole Pressure (CBHP) also eliminated tight spots and excessive reaming resulting in optimized drilling. The third formation used MPD as well to minimize overbalance pressure over previous sections while the fourth formation was drilled by UBD as it had a separate 6″ hole section as it formed an independent reservoir. The combined MPD and UBD approach eliminated most the NPT encountered in offset wells, enhanced Rate of Penetration (ROP) by 200% to 300% and slashed the well drilling time by 27 days.

Flood Control Method in Fields with Hard-To-Recover Reserves

This paper presents a method for predicting the development of Auto-HF (crack) in injection wells of the reservoir pressure maintenance system during the development of low-permeable reservoirs, in order to ensure the optimal front of oil displacement by water by regulating the bottom-hole pressure of injection wells based on the derived dependence of the half-length of the Auto-HF (crack).

MPD During the Global Pandemic in the Gulf of Mexico - How Virtual Meetings, Planning, and Communication Facilitated a Safe and Successful Implementation of CBHP MPD

This paper details how a major international operator was able to work directly with a Managed Pressure Drilling (MPD) service provider during the global pandemic to mobilize to a deep water Tension Leg Platform (TLP) in the Gulf of Mexico in fewer than four weeks from notification to being operationally ready. Apart from the time crunch, the challenging part was achieving it virtually without face-to-face meetings or rig visit. The legacy hydraulically controlled MPD system used on the previous well had proven to be very challenging. It could not provide the desired precise control to maintain the annular pressures within the operational window, thus necessitating a change. Furthermore, the deck space limitations had significantly restricted the equipment that could be used to gain accurate pressure control. Despite COVID, all the planning stages were performed, albeit virtually, and a compact modular electric servo choke MPD system was deployed, installed, and commissioned within four weeks from the initial discussions. The new MPD system, which replaced the legacy system, was successfully utilized on this project executing the constant bottom hole pressure (CBHP) MPD variations. It achieved bottom hole pressure (BHP) control within a 0.1 - 0.2 ppg operational window. This paper will discuss how, operationally, this 1-man per shift MPD crew communicated with the rig and operator personnel, delivered accurate pressure control on connections, performed dynamic formation integrity tests (FITs), delivering flawless execution, and meeting the client's expectations. Global pandemic made big changes in our work, learning and interact with people with social distancing.

Estimation of Bottom Hole Pressure in Electrical Submersible Pump Wells using Machine Learning Technique

With the growing importance and application of Machine Learning in various complex operations in the Oil and Gas Industry, this study focuses on the implementation of data analytics for estimating and/or validating bottom-hole pressure (BHP) of Electrical Submersible Pump (ESP) wells. Depending on the placement of the ESP in the wellbore and fluid gravity of the well fluid, there can be little or no difference between BHP and Pump intake Pressure (PIP); hence these two parameters were used interchangeably. The study focuses majorly on validating PIP when there are concerns with downhole gauge readings. It also has application in estimating PIP when the gauge readings are not available, provided the relevant ESP parameters are obtainable. ESP wells generally have gauges that operate on "Comms-on-Power" principle i.e. downhole communication is via the power cable and loss of signal occurs when there is no good electrical integrity along the electrical path of the ESP system. For proper hydrocarbon accounting and statutory requirements, it is important to have downhole pressure readings on a continuous basis, however this cannot be guaranteed throughout the life cycle of the well. Therefore, an alternative method is essential and had to be sought. In this study, the Response Surface Modelling (RSM) was first used to generate a model relating the ESP parameters acquired real-time to the PIP values. The model was fine-tuned with a Supervised Machine Learning algorithm: Artificial Neural Network (ANN). The performance of the algorithms was then validated using the R-Square and Mean Square Error values. The result proves that Machine Learning can be used to estimate PIP in a well without recourse to incurring additional cost of deploying new downhole gauges for acquisition of well and reservoir data.

New Method for Calculating Bottom Hole Pressure of Horizontal Well in Fracture-cavity Reservoir Based on Point Source Function

Accurate determination of unsteady bottom hole pressure helps to monitor and predict well production in real-time. On the premise of fully considering the seepage characteristics of carbonate rock, a new source function suitable for the seepage of carbonate rock is established. It enlarges the application scope of source function theory and lays a theoretical foundation for solving the seepage problem of carbonate rock. This paper presents the process of solving bottom hole pressure step by step. Step 1: Based on the triple media model, the Pedrosa permeability calculation formula is applied to establish the seepage model of the triple media reservoir considering the formation stress sensitivity. Step 2: By perturbation transform and Laplace transform, the point source function considering stress sensitivity in carbonate reservoir is obtained in Laplace space. The point source function in the infinite plate reservoir is obtained by the principle of mirror image and superposition. Step 3: The method of solving the horizontal well pressure under the constant pressure boundary is established. Through literature comparison and numerical simulation, the rationality of the proposed method is verified. Simultaneously, the sensitivity analysis of pressure and pressure derivative is carried out, and the influences of fracture number, fracture angle, fracture half-length, skin factor, horizontal well segment length, and horizontal well segment spacing on pressure and pressure derivative are analyzed in detail. Considering fracture orientation and stress sensitivity, we divide the triple media fracture-vuggy reservoir fluid flow into five stages. The number of fractures and fracture direction mainly affect stage C. In contrast, the length of horizontal subsection and skin factor mainly affect stage B. Stage D is more obvious when the fracture half-length and the horizontal sublevel interval of the horizontal well are small.

Interpretation of interwell connectivity tests in a waterflood system

This study is an extension of a novel technique to determine interwell connectivity in a reservoir based on fluctuations of bottom hole pressure of both injectors and producers in a waterflood system. The technique uses a constrained multivariate linear regression analysis to obtain information about permeability trends, channels, and barriers. Some of the advantages of this new technique are simplified one-step calculation of interwell connectivity coefficients, small number of data points and flexible testing plan. However, the previous study did not provide either in-depth understanding or any relationship between the interwell connectivity coefficients and other reservoir parameters. This paper presents a mathematical model for bottom hole pressure responses of injectors and producers in a waterflood system. The model is based on available solutions for fully penetrating vertical wells in a closed rectangular reservoir. It is then used to calculate interwell relative permeability, average reservoir pressure change and total reservoir pore volume using data from the interwell connectivity test described in the previous study. Reservoir compartmentalisation can be inferred from the results. Cases where producers as signal wells, injectors as response wells and shut-in wells as response wells are also presented. Summary of results for these cases are provided. Reservoir behaviours and effects of skin factors are also discussed in this study. Some of the conclusions drawn from this study are: (1) The mathematical model works well with interwell connectivity coefficients to quantify reservoir parameters; (2) The procedure provides in-depth understanding of the multi-well system with water injection in the presence of heterogeneity; (3) Injectors and producers have the same effect in terms of calculating interwell connectivity and thus, their roles can be interchanged. This study provides flexibility and understanding to the method of inferring interwell connectivity from bottom-hole pressure fluctuations. Interwell connectivity tests allow us to quantify accurately various reservoir properties in order to optimise reservoir performance. Different synthetic reservoir models were analysed including homogeneous, anisotropic reservoirs, reservoirs with high permeability channel, partially sealing fault and sealing fault. The results are presented in details in the paper. A step-by-step procedure, charts, tables, and derivations are included in the paper.

Assessing hydrocarbon prospects in Abu Madi formation using well logging data in El-Qara field, Nile Delta Basin, Egypt

In this work, the petrophysical properties of Abu Madi reservoir in El-Qara Field at northern Nile Delta Basin (NDB) were evaluated depending on well logging data of two wells: El-Qara-2 and El-Qara-3. This evaluation revealed that in El-Qara-2 well, the promising gas zone is detected between depths of 3315 and 3358 m, while in El-Qara-3 well, the best gas interval is detected between depths of 3358 and 3371 m. In addition to the production test parameters (gas rate, condensate rate, gas gravity, condensate gravity, gas-to-oil ratio, flowing tubing head pressure, flowing bottom hole pressure, and static bottom hole pressure), the calculated petrophysical parameters (shale volume, total porosity, effective porosity, and water saturation) for both intervals were relatively similar. This confirms that the investigated wells were drilled at the same reservoir interval within Abu Madi Fm. The depth variation in the examined zones was attributed to the presence of buried normal faults between El-Qara-2 and El-Qara-3 wells. This observation may be supported from the tectonic influence during the deposition of Abu Madi Fm. as a portion of the Messinian syn-rift megasequence beneath the NDB.

First MPD Project in Myanmar Successfully Completed on Deepwater Exploration Well

With the many challenges associated with Deepwater Drilling, Managed Pressure Drilling has proven to be a very useful tool to mitigate many hurdles. Client approached Managed Pressure Drilling technology to drill Myanmar's first MPD well on a Deepwater exploration well. The well was drilled with a Below Tension Ring-Slim Rotating Control Device (BTR-S RCD) and Automated MPD Choke System installed on semi-submersible rig, Noble Clyde Boudreaux (NCB). The paper will detail MPD objectives, application and well challenges, in conjunction with pore pressure prediction to manage the bottom hole pressure to drill to well total depth safely and efficiently. This exploration well was drilled from a water depth of 590m from a Semisubmersible rig required MPD application for its exploratory drilling due to uncertainties of drilling window which contained a sharp pressure ramp, with a history of well bore ballooning there was high potential to encounter gas in the riser. The Deepwater MPD package integrated with the rig system, offered a safer approach to overcome the challenges by enhanced influx monitoring and applying surface back pressure (SBP) to adjust bottom hole pressures as required. Additionally, modified pore pressure hunting method was incorporated to the drilling operation to allow more accurate pore pressure prediction, which was then applied to determine the required SBP in order to maintain the desired minimum overbalance while drilling ahead. The closed loop MPD circulating system allowed to divert returns from the well, through MPD flow spool into MPD distribution manifold and MPD automated choke manifold system to the shakers and rig mud gas separator (MGS). The automated MPD system allows control and adjustments of surface back pressure to control bottom hole pressure. MPD technology was applied with minimal overbalance on drilling and connections while monitoring on background gases. A refined pore pressure hunting method was introduced with manipulation of applied surface back pressure to define this exploration well pore pressure and drilling window. The applied MPD Deepwater technique proved for cost efficiency and rig days to allow two deeper casing setting depths and eliminating requirement to run contingency liners. MPD system and equipment is proving to be a requirement for Deepwater drilling for optimizing drilling efficiency. This paper will also capture detailed lesson learned from the operations as part of continuous learning for improvement on Deepwater MPD drilling.