Natural gas is one of the cleanest energy sources, its uses range from fueling power stations to cooking and heating. Global demand for natural gas is expected to rise in the coming years. Meeting these energy demands means drilling deeper exploration and development wells to access huge volumes of gas present under high pressure and high temperature (HPHT) conditions. Despite the attractiveness of the reward, managing the narrow drilling window between the reservoir pore pressure and the formation fracture gradient has remained a major source of cost escalation and non-productive time on HPHT projects. In order to improve the economics of HPHT projects, technologies like Managed Pressure Drilling and borehole strengthening have been used as a means of mitigating the risks associated with narrow margin drilling, thus enabling a paradigm shift from traditional casing seat selection methodology. In the Niger Delta, it is not uncommon to observe significant jumps in pore pressure values in proximate high pressure formations. The simplification of well designs and successful drilling operations are often challenged by the need to navigate through series of high pressured reservoirs in narrow margin windows. Compliance with process safety requirements requires selection of mud weight that is low enough to prevent mud loss and high enough to overbalance the reservoir pressure. Mud loss induced by formation fracture is often encountered in tight margin drilling, and when this happens, the focus shifts to strengthening the damaged wellbore using various techniques such as pumping chemical resins to seal off the loss zones. Various degrees of results have been achieved when borehole strengthening techniques are deployed with the objective of restoring wellbore integrity in both permeable and non-permeable formations. Successful deployments have resulted in achieving the well objectives safely and cost effectively. This paper details loss of wellbore integrity experienced on an HPHT well in the Niger delta and the wellbore strengthening strategy that was used to restore the strength in a non-permeable formation. It sheds light on how understanding the nature of the fracture, rock lithology as well as proper job execution can restore a damaged wellbore to its previous strengths. A Cost reduction approach to the execution of the strategy is also discussed.

The maturation and development of gas resources has of recent been on the front burner for many Oil & Gas producing countries and companies, mainly due to the drive for more environment friendly fuel and increasing demand for natural gas as a key driver for industrialization and growth. In Nigeria, the situation is not different, with proven reserves of 180 Tcf, but very low figures in production and utilisation of its gas resources, there has been an increased focus and push towards increased development in the natural gas sector. From the inception of oil and gas exploration in the late 1950’s to late 1990’s, most of the focus in the Nigerian Oil and Gas industry has been towards oil development, with little or no focus on gas, which led to the suspension of many exploratory/appraisal gas discoveries in several fields, with no plans of further development. The Zeta field is located in the Niger Delta region of Nigeria, with predominantly gas bearing reservoirs. Together with other nearby fields, it has about 9 Tcf of discovered GIIP. There is no existing infrastructure to process or evacuate the gas. Zeta field currently has four exploration and appraisal wells drilled between 1973 and 1987 and encountered 13 stacked reservoirs with a total expectation GIIP of about 2 Tcf and CIIP of about 100 MMstb. This paper highlights how opportunities in the gas sector has been maximized by deploying an innovative commercial and technical solution to unlock gas resources from a cluster of fields with large gas resource but not close to any evacuation facility. It shows how the existing exploration/appraisal wells has been planned for re-entry and side-track, to ensure a fast-tracked development of five Ready-To-Go (with no technically exploitable oil rim) reservoirs in the field. It also highlights how scalable reservoir models have been used in the development of the five reservoirs ensuring that the target onstream date is met.

Managed pressure drilling (MPD) is an adaptive drilling technique used to improve the economics and to mitigate risks associated with drilling high pressure and high temperature (HPHT) exploration wells where the drilling window is often narrow. The technique involves the combination of surface back pressure and fluid hydrostatic column to provide the required bottom hole pressure for safe drilling. Typical MPD equipment spread includes rotating control device (RCD), chokes, high pressure lines and gate valves with Pressure relief valves (PRVs) incorporated. The primary purpose of the PRV is to protect the MPD surface equipment and the formation from being overpressured. The relief valve achieves this by bypassing the normal fluid flow path for MPD operations and relieving the system pressure to the rig Mud gas separator (MGS) through a dedicated line. Each time a PRV is activated the resulting loss of surface back pressure increases the risk of taking a kick. On the other hand, when a PRV is not activated, an excessive increase in surface pressure raises the risk of formation fracture leading to losses. Therefore, the performance of the PRV has an immense impact on assessing the risk of a well control situation, which may be caused by either loses due to formation breakdown and consequently a kick from loss of the hydrostatic pressure component of the equivalent surface density (ESD) or an influx as a result of loss of surface back pressure component of the ESD due to loss of integrity of surface equipment). Pressure Relief Management philosophy generally covers decisions such as which parts of the well system (surface and subsurface) are to be preferentially protected by the PRVs, selection of activation pressure for high level alarms, types, number and setpoints of PRVs in the MPD system during different phases of the drilling operations - drilling, connections and tripping, and MPD choke full-opening pressure. These values are dependent on formation integrity test (FIT), mud weight, drilling window, annular friction pressure and operating envelope of RCD. The set points require adjustment depending on the hole size and flow rate and may be different during completion and well control operations. This paper describes the Pressure Relief Management philosophy for a HPHT well drilled in the Niger delta. It looks at factors that drive the high-pressure alarm setting values, choice of PRV types, placement and the part of the well system being protected, PRV tripping and reset values, and MPD choke full opening pressures. It also describes the challenges and risk assessment that influenced the selection of set points (single or dual setpoints) for different phases of the drilling operations.

The current volatility in the oil and gas sector underscores the importance of delivering consistent top quartile performance. To remain competitive, a robust performance management plan prior to drilling is key to successfully completing the project in time and under budget. Key Performance Indicators (KPIs) have historically been used to evaluate well construction performance. KPI targets are set to evaluate cost, time and quality of drilling operations. In The Shell Petroleum Development Company (SPDC), a benchmark method using the actual regional average performance data of similar wells drilled in the African region is used to generate high-level KPI targets (Macro KPIs) in terms of cost and time for ‘dry hole’ drilling. This method is recognised globally for target-setting and provides inputs used in forming a business plan. However, the use of Macro KPI targets to communicate performance requirements at the wellsite has been observed not to be as effective as required, since it does not clearly articulate performance required at the micro task level. It also does not allow effective real time monitoring of daily wellsite activities, making traditional performance monitoring retrospective. Micro KPIs are measures of smaller, repetitive actions that when added up, contribute a significant proportion of the time to drill a well. Breaking each phase of the drilling project into Micro KPIs (Tripping time, Running Tubular, BOP Testing and Handling, BHA Handling etc.) easily shows what it takes to win; what the sources of competitive advantage are; and what drives value. In order to make the transition from Macro to Micro KPI-based performance management flawless, the challenge of standardising Micro KPI target-setting needs to be addressed. This paper builds on the traditional performance management process, and by leveraging existing benchmark data, presents a process of generating and setting Micro KPIs for the drilling phase in an empirical and replicable manner.

Formation strength is an important parameter in drilling operations pressure control because it indicates the wellbore pressure containment envelope above which fracture or rock matrix failure starts to occur and propagate if the pressure/stress is sustained. The rock mineralogy, the orientation of wellbore with respect to the direction of regional fault line, the stress regime as well as the permeability of the rock determines the manner in which the rock would fracture. During well operations, situations that may result in the fracture of one of the formations traversed by the wellbore could arise, in which case, the main operations focus shifts to ensuring that the fractured formation is repaired before normal well operations can resume. One of the techniques of reinforcing or repairing a fractured formation is Wellbore Strengthening; which employs a variety of technologies such as deployment of resins and specially designed cement slurry. Over the years squeeze cementing success has greatly improved through studies and using best practices; however, wellbore strengthening through squeeze cementing still poses unique challenges of determining the location of the fractures that need sealing; and also whether these fractures are compatible with the designed cement slurry. Thus squeeze cementing, while being economical and effective, will only succeed if the job is properly designed and executed. This paper will demonstrate, through actual results, the feasibility of squeeze cementing as a means to restore wellbore strength by explaining the basic engineering that goes into designing a successful squeeze cement job for this purpose. It focuses on describing how the multidisciplinary approach of rock geo-mechanics, lithology, fluid mechanics, cement slurry design and proper job execution can contribute to the success of wellbore strengthening through squeeze cementing.