The objective of this study was to evaluate the role of strategic mergers and acquisition (M&A) as a panacea for success of marginal oil fields development in Nigeria and to make recommendations for policy decisions. Data for the study were obtained from literature review, document analysis and multiple case studies from operating marginal oil field companies in Nigeria. The cases of Platform Petroleum, Sheba Petroleum, Seplat and others were investigated and analyzed. These case studies identified how marginal field operator's utilized mergers and acquisitions in the form of business restructuring, consolidation, strategic alliances, joint venture formation and partnerships as a development support strategy to remain competitive in the oil and gas industry. Other mergers and acquisitions activities by other companies were also examined. The study findings revealed that strategic mergers and acquisition is one of the survival options for marginal field operators in Nigeria. Mergers and acquisitions enhances the business growth for the marginal oil fields operators by expanding the opportunity for raising capital required for oil and gas operations and provision of larger equity base; including provision of access to technology and manpower. As the oil price in the global oil and gas market remains low, investors in oil and gas business are looking for ways to cope with the fall in revenues. In this dynamic business environment, one fact remains unchanged, marginal oil field operators in Nigeria must re-strategise in order to survive. The marginal oil field operators in Nigeria are encumbered by inadequate funds and other constraints such as lack of capacity, low volume of production and inadequate technology, therefore they have to adopt one of the critical success factors for business survival in a challenging environment. Herein lies the role of strategic mergers and acquisitions. The findings of the study will serves as a decision-making frame work for investors in oil and gas business wishing to participate in the sustainable management of marginal oil field in Nigeria. The study recommendations indicate that policy makers in Nigeria should create a favorable investment climate among which are: stable macro-economic policies, legal system that allows contracts to be enforced and clearly support access to channel of arbitration.

In the Freeman Field, located about 120km offshore southwestern Niger Delta at about 1300m water depth, 3D seismic attribute-based analogs, and structural and stratigraphic based geometric models are combined to help enhance and constrain interpretation. The objective of this research was to aid in the prospecting of Miocene to Pliocene Agbada Formation reservoirs in the deep offshore Niger Delta Basin. Multidisciplinary approaches – analysis of root-mean-square amplitude attribute, iterative integrated seismic interpretation and structural modeling, were employed in this study. Results reveal a massive northwest-southeast trending shale-cored detachment fold anticline containing numerous associated normal faults. This structure is interpreted to have been deformed by differential loading of the undercompacted, overpressured, and ductile Akata shale during syndepositional gravitational collapse of the Niger Delta slope. Crestal extension in the anticline resulted in a complex array of synthetic and antithetic normal faults, which include crossing-conjugate pairs. These conjugate structures could significantly affect permeability and reservoir performance. Crossing-conjugate faults have not previously been recognized in the Niger Delta, and similar structures may be present in other hydrocarbon-trapping structures in the basin. Also, the Miocene to Pliocene Agbada Formation reservoirs occur as part of a channelized fan system, mostly deposited as turbidites in an unconfined distributary environment, except one reservoir sand that occurs as channel sand within a submarine canyon that came across and eroded a previously deposited distributary fan complex, suggesting likely presence of prospective areas for hydrocarbon exploration southwest of the Freeman Field.

Presentation Date: Thursday, October 18, 2018

Start Time: 8:30:00 AM

Location: 210A (Anaheim Convention Center)

Presentation Type: Oral

Well placement within thin and discontinuous reservoirs continues to prove challenging in present-day field development. Some geological objectives require draining accumulations within discontinuous reservoir fairways with thin true vertical depth (TVD) thickness (<7 m). The ability to geosteer within these complex systems using modern azimuthal tools has provided some solutions; however, there are multiple other elements contributing to successfully landing a drain with such reservoir scenarios.

Turbidite channels are common within the offshore Niger Delta systems and in many other basins. The Niger Delta Basin is predominately a clastic system, and the reservoir targets in this fairway are a mix of structural and stratigraphic traps made up of sand and shales deposited during the Early Pliocene period. These systems are generally described as turbidite channellevee complexes.

This paper discusses a case study using two recently drilled wells to analyze the technique/approach used for a successful and safe well placement operation. This approach involves two parts: the use of technology (geosteering tools) and the role of communication for a successful well placement operation. The primary tool used was azimuthal deep resistivity, which uses resistivity contrast within beds to help geosteer and stay within reservoir bodies, hence optimizing well placement. Guided by azimuthal resistivity imaging, it was possible to determine the well direction relative to the beddings using oriented binned data and resultant images.

The communication aspect involved prejob, on-the-job, and post-job elements that contributed extensively to successful operations. A closed-loop approach to decision making was implemented whereby azimuthal resistivity data (and geosignal ratio curves) were measured and transmitted in real time, then analyzed by a team in the office collaboration room who transmitted information back to the rigsite for implementation. This paper also documents the uncertainties associated with the measurements and the processes available to mitigate them as well as lessons learned.

Two wells were placed within undrilled fairways with reservoir and depth uncertainty. With the help of pilot holes 6 and 7-m TVD thick, hydrocarbon sands were discovered. Drains of 400 and 700 m were placed within these fairways, and each well exhibited good productivity. Interpretation of geosignals measured while drilling along with real-time follow-up on the seismic and knowledge of the geological setting were instrumental in the successful placement of these producing wells. The decision-making and analysis process was optimized, thereby achieving operational excellence (health, safety, and environment and timing) and cost savings. The most significant element of these operations is communication. The ability to analyze information and implement decisions rapidly involved all essential disciplines from service company personnel to drilling and completions to geosciences.

Advancements made in geosteering technology and lessons learned from this case study can be applied to future well planning for geological targets originally assumed to be difficult, impossible, or too thin to be successfully drilled to increase field productivity.

The experiences garnered in drilling deep wells in the Nigeria Delta Basin of Nigeria are presented herein. The referenced wells were drilled to the deep target series of gas and gas condensate reservoirs at depth range of 4900m - 5530m. The total volumes of the targeted reservoirs are about 60mmstb of oil and 1400bscf of gas. There were challenges of stuck pipes in phases through some depleted zones/reservoirs that were resolved through brainstorming with the production unit of the company. Other challenges encountered and highlighted are in hole stability, bit selection, Well control, HSE, rig efficiency and cost performance. Drilling the wells in sequence exploits the benefits of immediate application of gathered experiences from the previous wells. This paper presents the key challenges associated with the drilling of deep wells as experienced in the referenced wells.

Drilling through shale formation can be challenging and sometimes results in wellbore instability problems due to the reaction between hydrophilic shale and drilling fluids. The typical low permeability of shale, the presence of ions and charged surface of the constituent clay are factors which makes the problem of wellbore instability very complex despite efforts dedicated to the study by researchers. The study of wellbore stability in shale is quite important because 75% of all formation drilled worldwide are shale formations and 90% of all wellbore instability problems occur in shale formations costing the industry more than $1 billion USD/year (Chenevert, 2002; Zeynali, 2012); the lost time due to this challenge also account for over 40% of all drilling related non-productive time (Zhang et al, 2009) and these instabilities are responsible for 10-20% of the total drilling cost. A solution through this challenge is critical to the sustenance of the investment made by operating companies in the oil and gas industry. This will drastically reduce drilling cost, completion and workover cost as well as the accompanying downtime involved. It will also improve the net present value of operating company in the industry. Basically wellbore instability occurs when the mechanical stress induced by drilling into the formation exceeds the formation rock strength. Chemical interactions between the drilling mud and the in-situ shale affect the in-situ stress state of the formation hence the stability of the formation. Geo-mechanical models have been designed to tackle mechanical wellbore instability in the Niger Delta the challenge therefore is a chemical solution to the wellbore instability problems of the region. Oil-based muds have been known to overcome wellbore stability problems, but disposal challenges and environmental concerns have led to infrequent use. The challenge therefore is to formulate an environmentally friendly drilling mud having the inhibitive properties to tackle the wellbore instability challenges. This paper presents a review of studies carried out to characterize the mineralogy of shales and the salinity distribution of formation water in the Niger Delta depobelts with a view of designing a "balanced-activity" drilling fluid to help stabilize the formation during drilling. Results obtained from the reviewed researches showed that shale mineralogy characterization and formation water salinity distribution is critical in designing a balanced-activity drilling mud that can effectively tackle the problems of wellbore instability.

The global oil price as well as Nigeria’s current reserve is on a continuous alarming decline. With the increasing finding cost of new wells and demand for energy, improving oil recovery from existing wells becomes highly pertinent. Generally, waterflooding leaves approximately two thirds of the OIIP as un-swept or residual oil resulting to a low recovery factor. The improvement of recovery factor is one of the identified five Research & Development (R&D) grand challenges or upstream business needs highlighted by the SPE R & D committee. Enhanced Oil recovery (EOR) methods provide an avenue to Petroleum engineers to unravel this challenge. In lieu of this, we investigated the feasibility of improving recovery with polymer flooding technique in the Niger Delta region of the Sub-Sahara Africa. A sequence of brine saturation, oil saturation, water flooding and polymer flooding was carried out on four different cores (core A, B, T & R). Core A & B are ROBU cores (specially manufactured synthetic cores), T is Bentheimer core and while R is a reservoir rock core sample from a shallow central Onshore Niger Delta reservoir.

The results show comparative responsiveness of oil recovery to polymer flooding by the various core samples. Core samples T & R are good candidates for polymer flooding having produced 21.28% & 13.33% after polymer flooding. Model Bentheimer rock sample (T) which has close petro-physical properties to that of the case studied reservoir has the highest displacement efficiency of 52.63%. The core flood analysis demonstrated that polymer flooding could improve oil recovery within the Central Onshore reservoir of the Niger Delta.

Summary
Multiattribute seismic analysis and stratal slicing had proved very useful in the detection of near-surface deep-water channels and depositional facies. The integration of deep-water channel morphology and facies architecture with modern fluvial systems and ancient Tertiary outcrops has improved our understanding of the eastern offshore Niger Delta deep-water sedimentology and reservoir distribution. Subaqueous extension of sediment-ladden fluvial channel arising from sustained flooding events are referred to as hyperpycnal systems. These constitute very efficient mechanisms for transporting large quantity of sands into the Niger Delta basin setting. The movement of land-derived hyperpycnal deposits does not require steep slopes, as the energy of flow is maintained by river discharge during flood. These hyperpycnal deposits are characterized by gentically related facies of bed-load, suspended-load and lofty transport processes respectively. Flood-dominated fluvial-deltaic systems have genetic relationship to hyperpycnal depositional model in the deep-water Niger Delta. These are characterized by channel levee complexes and submarine fan lobes.

The objective was to resources currently are produced from the sandstonedetermine the ability of using the flow rate to control the species within the Agbada formation. Results show that the sand production in the upper Akata formation is a potential target inis both affected by the flow rates, the confining pressure, deepwater offshore and currently producing intervalthe drawdown and the viscosity of the formation fluid. Currently sand production is considered as oneHigh sand-free flow rates can be achieved if the sand of the major problem in the petroleum industry in Niger-formation is mechanically confined (compacted). Every year, well cleaning and workovergrain size distribution of the produced sand in the operations related to sand production and restrictedlaboratory is identical to that of the field sample. At high production rates cost the industry millions of dollars.confining

Problems encountered during initial trials of cuttings injection (CI) in Nigeria resulted in the technology being perceived by regulators as an infeasible disposal option in the Niger Delta basin and it was considered to be removed from the approved list of disposal options. This study was conducted to review the disposal technology, assess the deficiencies in the initial trials with respect to the Niger Delta geology, and proffer a framework for an environmentally-feasible application of the technology. The results of the study revealed that the geology of the Niger Delta is favorable for CI operation because of favorable lithology and a lack of strong seismic events. However, due to variations in the depth of the base of fresh water a suitable injection domain cannot be mapped across the Niger Delta basin. Therefore, each project needs to be evaluated on a case-by-case basis using site-specific information.

The lessons learned from the previous practices were identified and an integrated project approach was recommended to achieve an environmentally appropriate use of CI in the Niger Delta basin.