To date, several wells have been drilled in the Friesland/Groningen area of northern Holland. Historically, catastrophic cutter damage/failure in the 12 1/4" Triassic section resulted in inconsistent and unacceptable bit performance. Here, the Triassic is an interbedded formation containing hard dolomite and anhydrite stringers and abrasive sands. The transition from a softer to harder formation at high inclination evidently initiated bit and drillstring vibrations, thus causing premature cutter failure of the PDC bits used in the program. This paper presents a detailed analysis of the 12 1/4" section conducted after the drilling of Well No. 1. The recommendations arising from the study concentrated on the use of a real-time downhole vibration monitoring or VSSMWD tool (Vibration Stick Slip) in combination with revised drilling practices to reduce vibrations when encountering the interbedded formation. Thus, on Well No, 2, nearly all of the 2358-m Rijnland and the hard and abrasive Triassic forrntions were drilled with one PDC bit on a rotary assembly, where previously six bits were required. The authors will illustrate the benefits of a detailed interval analysis and discuss the role of the VSS system and the dring crew in addressing catastrophic drillstring and bit vibrations. P. 925

The Adanga Field was discovered in 1974 and is located offshore Calabar in the central part of OML-123 in Nigeria territorial waters. Addax Petroleum took over operatorship of the fields in 1998, when the production from Adanga was just 2,000 BOE per day. Through introduction of new technology, field production increased to over 20,000 BOE per day by 2009. Poor productivity and increasing water cut is an issue in Adanga. Re-interpretation of 3-D seismic data and incorporating additional information from new wells 3-D reservoir modeling confirmed an economic hydrocarbon pool to the west of Adanga (ADW). Additional reservoir targets were identified in the Adanga South field. The plan was to develop these reservoirs from existing infrastructure. Unfortunately, the existing Adanga South platform had no remaining slot capacity to drill new wells without additional infrastructure investment. Upgrading the platform with additional drilling slots was deemed uneconomical, unsafe and will increase collision risk. The platform on adjacent field, Adanga South West, did have drilling slots available, so it was decided to investigate the feasibility of drilling extended reach wells from the Adanga South West platform to access these otherwise stranded reserves in the Adanga South field Challenges in drilling these wells include the weak nature of the formation which can pose difficulties to conventional directional drilling techniques, wellbore quality and ECD management. This paper describes the planning, engineering and execution of constructing two; complex, 3D, horizontal, extended reach wells drilled on the Adanga Field in 2010 to access locked-out reservoir in adjacent field. Using the experience from these two wells, the challenges of drilling complex, high angle wells in the weak sediments of the Niger Delta will be discussed along with how these wells were ultimately drilled and geologically positioned for optimum recovery.

Drilling Exploratory and Appraisal wells can be challenging especially when faced with narrow mud weight / formation breakdown gradient windows and the potential for rapid pressure ramps. Operators engaged in the search for, and production of, hydrocarbon reserves in Tertiary basins are frequently confronted with complications associated with over pressured (abnormally high fluid pressure) formations. This is particularly the case in some of the Offshore Assets of Addax Petroleum. The problems associated with these formations are of direct concern to the combined activities of all phases of operations, which include geophysical, drilling, geological and petroleum engineering, thus the knowledge of the pressure distribution of a given area of operations would greatly reduce the magnitude of many of these complexities and in some cases, would completely eliminate them. This paper presents how the use of the Baker Hughes INTEQ "TesTrak™" tool has been used to measure formation pressures while drilling (before switching off pumps to make connections). On one exploration well, it was observed the well flowed when the pumps were switched off to make a connection, thus indicating the Equivalent Circulating Density (ECD) was providing the overbalance over the formation pressure. It is also important to note that there has been a transition in optimizing the efficiency and functionality of this tool where the the Bottom Hole Assembly (BHAs) have been re-configured with the TesTrak™ being run "upside down" so that the formation pressure measuring probe would be closer to the bit and thus enable the earliest possible formation pressure information, minimizing the likelihood of a pumps off event. The process of automatic cycling of the pumps, which was required to toggle the tool back to drilling mode was minimized (only with full knowledge and agreement of all involved in drilling operations), after it was observed how dangerous it can be loosing the the over-balanced supplied by ECD. To maximize the advantage of having the logging tool read formation pressures real time, the TesTrak™ has been used to take formation pressures to verify prognosed pressure transition zones such that the mud weight can be adjusted to suit the actual pore pressure measured.The TesTrak™ tool is presently also being used by Addax Petroleum for data gathering while drilling development wells eliminating the need to run wire-line or pipe conveyed logging in highly deviated and horizontal wells. This has saved rig time and drilling operations costs in addition to enhancing drilling efficiency. It has also improved well-site safety, helped optimize decision making and decreased the risk of differential sticking.

Directional drilling control in top-hole sections through very weak shallow sediments is challenging. The formation tends to wash out, reducing steering control. The lack of reliable steering results in well kick-off-points planned deeper than optimal, especially for extended-reach wells or under multi-well platforms where early well separation is advantageous. Additionally, when drilling in close proximity to existing wells, well collision risk increases. As a result of these challenges, a major operator and international service company have developed, and proven, a hybrid drilling technique enabling reliable steering control in sediments which previously proved difficult to directionally drill through. The technique employs an automated rotary steerable system (RSS) and gyro-while-drilling tool operating in a directional jetting mode without rotation. The wells are drilled from an offshore platform through dual conductors. In addition to the well collision risks normally associated with multi-slot platforms, dual conductors mean that the second well drilled from each conductor is initially in very close proximity to the first well. Until this technique was developed, the top-hole sections were drilled with steerable motors because RSS were unable to steer consistently in the very weak shallow sediments. When the collision risk was passed, and the formations became firm enough for the RSS to operate, the steerable motor bottom hole assembly (BHA) was replaced with the RSS. The hybrid RSS jetting technique provides several advantages; a single BHA run can drill to section TD, shallower kick-offs are possible and predictable steering control reduces the risk of collision. The lower energy of the non-rotating jetting system is also believed to reduce damage to an offset well in the event of collision. The paper explains how the hybrid system was developed, and describes how it is applied and optimised in practice with real examples. Opportunities for further research are presented which may enable offset wells to remain on production, saving significant production loss and avoiding risk associated with well shut-in and start-up.

This paper describes the successful technique to start a kickoff below the 36-in. conductor casing with much higher dogleg severity (DLS) capability than a conventional motor directional drilling method in a soft sediment formation by using a rotary steerable system (RSS) equipped with directional jetting. This technique uses a rotary steerable system (RSS) equipped with directional jetting to provide the operator with a step change in directional well design for reaching shallow reservoirs with inclinations close to horizontal. The challenging aspect of the well design was that only 650m (2133ft) of TVD was available to perform the directional work. This section consisted of weak and soft sediment formations that did not support conventional directional drilling methods. To address the operator's challenge, it was determined that a RSS configured for directional jetting could deliver the higher DLS for the optimal well trajectory. This system combines two techniques, rotary steerable and directional jetting, to achieve the directional objective. This field-proven application was successfully used by several operators, as described in SPE-173057-MS, and applied in this deepwater low-UCS environment. The extensive engineering evaluation, using finite-element analysis and torque-and-drag calculations, confirmed the bottom hole assembly (BHA) design was technically feasible without compromising safety and drilling efficiency. Three wells successfully delivered all directional objectives with this technique. The highest inclination was recorded in the top hole as planned; the sailing angle was lower compared to other wells drilled with conventional directional drilling methods, and the target sands reached at an angle close to horizontal. Completions ran without issues. This technique delivered above 3°/30m DLS in the deepwater soft formation and all future wells for this operator will use this technique for the tophole drilling.