HPHT 101-What Petroleum Engineers and Geoscientists Should Know About High Pressure High Temperature Wells Environment

On April 20, 2010, BP’s Deepwater Horizon oil rig exploded in the Gulf of Mexico. This turned out to be one of the worst environmental disasters in recent history. This high-profile blowout at the Macondo well in the Gulf of Mexico, brought the challenges and the risks of drilling into high-pressure, high-temperature (HPHT) fields increasingly into focus. New Technology, HSE regulations, new standards, such as newly recommended procedures by the American Petroleum Institute (API), and extensive training programs for the drilling crew seem to be vital in developing HPHT resources.  High-pressure high-temperature fields exist in Gulf of Mexico, North Sea, Southeast Asia, Africa and the Middle East. Almost a quarter of HPHT operations worldwide are expected to happen in the American continent particularly in North America. Major oil companies have tried to identify key challenges in HPHT development and production, and several service companies have offered many insights regarding current or planned technologies to meet these challenges. However, there are so many factors that need to be addressed and learned in order to safely overcome the challenges of drilling into and producing from HPHT oil and gas wells.Drilling into HPHT wells is a new frontier for the oil and gas industry. The growing demand for oil and gas throughout the world is driving the exploration and production industry to look for new resources. Some of these resources are located in deeper formations. According to US Minerals Management Service (MMS), over 50% of proven oil and gas reserves in the US lie below 14,000 ft. subsea. As we drill into deeper formations we will experience higher pressures and temperatures.Drilling operations in such high pressure and high temperature environments can be very challenging. Therefore, companies are compelled to meet or exceed a vast array of technical limitations as well as environmental, health and safety standards.  This paper explains the technological challenges in developing HPHT fields, deepwater drilling, completions and production considering the reports from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), formerly known as the Minerals Management Service (MMS). It reviews the HPHT related priorities of National Energy Technology Laboratory (NETL), operated by the US Department of Energy (DOE), and DeepStar Committees for Technology Development for Deepwater Research

A Method for Cement Integrity Evaluation in Unconventional Wells

Chances of cement sheath failure increase considerably when the application involves deep, high pressure/ high temperature (HPHT) wells. Such failures occur as a result of temperature and pressure-induced stresses created by well events such as hydraulic fracturing, well testing, enhanced oil recovery, completion, production, and work over, or other remedial treatments. These would impose huge operational costs and in some circumstances lead to loss of production. Analytical and FEA modeling research has been done in the past but fewer experimental studies focused on finding the fatigue endurance cycles of oil well cements under HPHT conditions. Abundant unconventional resources, producing from deeper horizons, numerous frac jobs in the US, and safety significance were the prime motivations for creating a new testing procedure for evaluating cement integrity under HPHT conditions. A novel HPHT cell was manufactured and mounted on a Chandler 7600, an extreme HPHT Rheometer. Cylindrical cement samples were cured and tested at constant confining pressure while the casing pressure varied cyclically. These samples failed after a certain number of cycles when reaching their fatigue endurance limit or if they had inconsistent chemistry to withstand the HPHT conditions. This research explains a method for cement integrity evaluation and identifies the fatigue failure cycles for 1,000 psi, 2,000 psi and 5,000 psi pressure differentials between the confining pressure and maximum casing pressure. Class H cement and class H plus 35% silica were used in these experiments and cement failures such as radial cracking, debonding and disking were observed

Comparative Study of Using Oil-Based Mud Versus Water-Based Mud in HPHT Fields

Growing demand for oil and gas is driving the exploration and production industry to look for new resources in un-explored areas, and in deeper formations. According to the Bureau of Ocean Energy Management, Regulation and Enforcement, former Minerals Management Service (MMS), over 50% of proven oil and gas reserves in the United States lie below 14,000 ft. subsea. In the Gulf of Mexico some wells were drilled at 27,000 ft below seabed with reservoir temperatures above 400 °F and reservoir pressures of 24,500 psi. As we drill into deeper formations we will experience higher pressures and temperatures.Drilling into deeper formation requires drilling fluids that withstand higher temperatures and pressures. The combined pressure-temperature effect on drilling fluid’s rheology is complex. This provides a wide range of difficult challenges and mechanical issues. This can have negative impact on rheological properties when exposed to high pressure high temperature (HPHT) condition and contaminated with other minerals, which are common in deep drilling. High Pressure and High Temperature (HPHT) wells have bottom hole temperatures of 300 °F (150 °C) and bottom hole pressures of 10,000 psi (69 MPa) or higher.Water-Based mud (WBM) and Oil-Based mud (OBM) are the most common drilling fluids currently used and both have several characteristics that qualify them for HPHT purposes. This paper compares the different characteristics of WBM and OBM to help decide the most suitable mud type for HPHT drilling by considering mud properties through several laboratory tests to generate some engineering guidelines. The tests were formulated at temperatures from 100 °F up to 600 °F and pressures from 5,000 psi to 25,000 psi. The comparison will mainly consider the rheological properties of the two mud types of mud and will also take into account the environmental feasibility of using them. Key words: Oil-based mud; Water-based mud; HPHT field

Hydrogen Embrittlement of Nanostructred Bainitic High Strength Steel

Characterization of nanostructured bainitic high strength steel revealed austenitic and bainitic-ferritic constituents. Hydrogen diffuses through austenite slower than bainitic ferrite. Discovering the effective hydrogen diffusion coefficient, subsurface hydrogen concertation and number of traps of such a microstructure leads to a deeper understanding of the role of retained austenite, as the dominant trap in such microstructures. Devanathan– Stachurski hydrogen permeation experiments determined the permeation parameters and subsequently numbers of reversible and irreversible traps. Volume of the retained austenite correlated well with the total number of traps and the mean free path. Lower mean free path, higher austenite content and trap density and more importantly finer dispersed distribution of films of retained austenite alongside with thin plates of bainitic ferrite satisfied percolation through the austenite. Therefore, permeation experiments demonstrated the lowest diffusivity in 2000 MPa microstructure between all the bainitic high strength membranes. On the contrary, combination of granular morphology and smaller volume of retained austenite triggered the loss of percolation and yielded to the lowest diffusivity for 1000 MPa microstructure. Higher volume of the retained austenite in isolation in the nanostructured bainitic steel does not produce lower diffusivity. With a semi analytical nonlinear fracture mechanics model and NTSSRT, we evaluated the hydrogen embrittlement susceptibility of the 1600 MPa exposed to H2S and the 2000 MPa steels exposed to hydrogen charging. At a certain hydrogen concertation, pre-charged samples showed greater decrease in hydrogen embrittlement index and J integral drop