Fabbri, C. (TOTAL E&P Nigeria Limited) | Imeokparia, O. (TOTAL E&P Nigeria Limited) | Odeniyi, A. (TOTAL E&P Nigeria Limited) | Ibekwe, K. (TOTAL E&P Nigeria Limited) | Udoh, D. (TOTAL E&P Nigeria Limited) | Lanisa, A. (TOTAL E&P Nigeria Limited) | Fashanu, M. (TOTAL E&P Nigeria Limited)
In the Amenam-Kpono field, the main reservoir (R4) is characterized by vertically stacked deltaic sand bodies that are laterally extensive but with intercalated shale layers. Pressure maintenance is by both water and gas injection. Gas injectors are located on the crest of the anticlinal structure in order to re-inject the gas in the gas cap, while water injectors are located at the edge, injecting treated sea water into the aquifer. The R4 reservoir is divided into four disconnected hydrocarbon bearing flow units. The field has 35 development wells and more than 13 years of production (1st oil in July 2003).
Due to the layered nature of this reservoir, saturation logging is carried out regularly in order to check the contacts evolution at the well, even within the same flow-unit. Indeed, one of the main concerns since the start of water injection in R4 is understanding the communication between injectors and producers, which might lead to water cut increase and loss in productivity. This paper describes the measurements performed on an Amenam-Kpono well to evaluate a 20m additional perforation in flow-unit#1 (FU1). Two different measurements were carried out: saturation logging (oil saturation in the formation) and water flow log (measuring the water velocity around the tool). Integration of both results enabled the selective design of 20m additional perforation, leading to an oil incremental gain of 5800 bopd.
Fabbri, C. (TOTAL E&P Nigeria Limited) | Poirier, Y. (TOTAL E&P Nigeria Limited) | Odeniyi, Odeniyi (TOTAL E&P Nigeria Limited) | Mayembo-Kehoua, D. (TOTAL E&P Nigeria Limited) | Imeokparia, D. (TOTAL E&P Nigeria Limited) | O. Udoh, D. (TOTAL E&P Nigeria Limited) | Umoh, E. (TOTAL E&P Nigeria Limited) | Lanisa, A. (TOTAL E&P Nigeria Limited) | Fashanu, M. (TOTAL E&P Nigeria Limited) | Tremaudant, C. (TOTAL S.A.)
In the Amenam-Kpono field, three main reservoirs are currently being produced: R11, R10 and R4. During the first phase of its development, the production strategy was to re-inject the associated gas from all reservoirs into the R4 reservoir in order to maintain the initial reservoir pressure above the saturation pressure, close to initial pressure. The deeper reservoirs R10 and R11 were first produced under natural depletion as their initial pressures were far from saturation pressure. Water injection was progressively deployed on R4, R10 and R11 in order to ensure voidage replacement.
In order to monitor the efficiency of gas injection, a gas tracing campaign has been carried out in 2005, improving the understanding of R4 flow barriers and showing that some of the gas injected had broken-through. However, ideally, such a campaign should be repeated regularly so as to take into account the change in pressure regimes that will affect the dynamics of the field. In practice, implementing it regularly is challenging, due to the cost associated to the chemicals and logistics. This paper aims to describe a "low cost" monitoring method based on produced gas composition follow-up and its evolution through the life of the field. It shows how the composition of the gas produced has been recently used as a natural tracer. This approach has improved the understanding of the reservoir dynamics, in terms of compartmentalization and flow distribution across different perforations.
Otevwemerhuere, J. (Addax Petroleum) | Nwosu, C. (Addax Petroleum) | Olare, J. (Addax Petroleum) | Jefford, Leigh (Addax Petroleum) | Parkins, Steve (Addax Petroleum) | Cavalleri, C. (Schlumberger) | Shrivastava, C. (Schlumberger) | Espinosa, H. (Schlumberger) | Mougang, M. (Schlumberger)
Low resistivity low contrast (LRLC) reservoirs have been successfully produced for many years; however detection and detailed description of their properties and potential would remain a challenge in absence of an exhaustive formation evaluation program. Proper understanding of the geological evolution of such reservoirs to explain their distribution and variations in petrophysical properties is also vital.
Low resistivity pay reservoirs encountered in West Africa are often characterized by variation in resistivity values in vertical and horizontal directions due to fine grains and conductive layers within the coarse grained sands and clearly marked sand-shale laminations. This is accurately solved by tri-axial induction resistivity measurement in combination with high resolution measurements able to define any contributing layer level-by-level through robust anisotropic interpretation methods. However, heterogeneity, mixed clays effect, and complexity in rock texture require new technology and innovative interpretation models in multi-domain approach.
Advances in logging technologies, interpretation software, and analytical methodologies enable better and more refined reservoir models to be fashioned and tweaked as needed on a case-by-case basis. The case study analyzes log responses, implication of heterogeneity and mixed clays content on the generation of LRLC pay reservoirs in deltaic environment offshore Nigeria.
Precise application of advanced log measurements and integration of core data in a common workflow, built around the concepts of evolution of LRLC reservoirs lead to accurate pay quantification. Borehole image interpretation suggests that the low resistivity contrast is attributed to dispersed clays coating around the sand grains in the toe part of a delta front in major coarsening up and feeble fining up sequences. This is also confirmed by variations of elastic properties of the matrix.
Petrophysical logs recorded at high resolution correlate inferring the main causes of LRLC pay are clay content and distribution, and small grain sizes intermingled to the reservoir rock, hence resulting in low resistivity values in all directions and drastically increased irreducible water. The logs based model is confirmed by calibration to core analysis results. The confident results of the study confirm the power of collaboration between petrophysics, rock mechanics and geology in innovative interpretation workflows for enhanced reserves estimate and Producibility prediction in heterogeneous media.
Ndokwu, Chidi (Baker Hughes) | Okowi, Victor (Baker Hughes) | Foekema, Nico (Baker Hughes) | Caudroit, Jerome (Addax Petroleum Development) | Jefford, Leigh (Addax Petroleum Development) | Otevwe, Joseph (Addax Petroleum Development) | Fang, Xiaodong (Addax Petroleum Development) | Idris, Maaji (Addax Petroleum Development)
High-angle or horizontal wells pose many geological challenges that include maintaining well trajectory within a particular horizon in drain sections, detecting stratigraphic positions after passing a discontinuity, and subsurface feature identification. Geo-steering has shown increased value over the years because it uses data from different sources, including borehole imaging, to meet these challenges. Bulk density and gamma ray borehole images can be used to describe the near-wellbore environment, and that description can be analyzed further to explain the near-wellbore structural geology. In this study, structural analysis and zonation of bulk density and gamma ray images were used to detect the fault zone, while a geo-steering application was used to pick the true stratigraphic depth after crossing the fault. Provision of an alternative model to seismic-only interpretations and a better understanding of subsurface structures are the industrial benefits of this study. The Niger delta sedimentary basin of Southern Nigeria is a prograding depositional complex of Cenozoic-aged sand and shales that extends from about longitude 3 - 9 E and latitude 4 30' - 5 20' N. This paper demonstrates the importance of geo-steering, shows the application of geo-steering in a high-angle well drilled in the Niger delta sedimentary basin, and establishes the importance of structural analysis from borehole images in making final geo-steering interpretations. This paper also shows that borehole imaging is an additional and useful source of information in the planning stage of any drilling campaign.
As the industry pushes the boundary of technology to drill narrow-margin wells, combining safe drilling practices with drilling efficiency is becoming ever more challenging. The practice of drilling with managed-pressure drilling (MPD) by use of statically underbalanced mud weight (MW) is gaining increasing acceptance in high-pressure/high-temperature (HP/HT) well construction. This paper describes the planning and execution of using mud-cap fluid in the drilling of an ultranarrow-margin (0.50-lbm/ gal window at the planning stage) HP/HT well from a jack-up rig. Drilling equivalent circulating density with overbalanced MW at acceptable flow rate would have exceeded the formation-fracture gradient and resulted in a loss of well integrity. To avoid this outcome, the HP/HT section of the well was drilled with statically underbalanced MW. Displacing well to kill-weight fluid at acceptable flow rates before any trip out of hole was not viable. Planning focused on how to maximize operational efficiency with a cap fluid to trip in and out of hole without compromising openhole integrity and well safety. In this paper, we discuss the design of the mud-cap fluid, selection of change over depth, risks associated with use of the cap fluid, determination of available window for mud-cap placement and removal, planning and execution of mud-cap placement and removal, challenges of running and displacing the cap fluid with a liner, and lessons learned from the repeated use of the technique throughout the well-construction phase, including coring and wireline logging under MPD conditions. Significant operational efficiency was gained from the use of cap fluids, making it possible to drill a well that would otherwise have been near impossible to drill with minimum lost time.
In the Amenam-Kpono Field, six of the hydrocarbon bearing reservoirs encountered are currently developed. The Main Reservoir (R4) is characterized by vertically stacked sand bodies with intercalated shale layers, laterally well extended.
In the initial reservoir study, a low vertical reservoir permeability (Kv/Kh=0.01) and maps of vertical transmissibility within these shale layers were implemented in the dynamic model.
In fall 2007, Amenam East well confirmed an excellent lateral communication with Amenam Main Field through the aquifer and highlighted the presence of multi disconnected hydrocarbon bearing flow units within R4 reservoir of the Amenam-East structure.
It was assumed in the initial Field Development Plan that these shale layers would play a crucial role in fluid dynamics and hydrocarbons recovery. The initial dynamic model was used to optimise well location and perforation strategy.
With 35 development wells drilled and almost five years of production (1st oil in July 2003), the significant impact of vertical shale barriers was confirmed and 4 main dynamic units were identified in the R4 reservoir. Data acquisition during the development phase and early production life of the field with pressure data, interference tests and gas tracers yielded very significant results, essential to optimise the development strategy and to establish a proper reservoir management scheme of the Amenam-Kpono field.
A limited number of corrective actions were implemented, mainly with 4 additional wells in 2007-2008, drilled to sustain pressure and/or to enhance recovery in the under developed R4 bottom unit.
This article is a synopsis of paper SPE 39482, "Fines-Migration Control in High-Water-Cut Nigerian Oil Wells: Problems and Solutions," by Toni Ezeukwu, Ashland Oil Nigeria Co.; R.L. Thomas, SPE, Dowell; and Terje Gunneroed, Dowell Nigeria, originally presented at the 1998 SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, 18-19 February.
Although fines migration has been investigated in the laboratory and the field for more than 30 years, severe loss of production resulting from fines migration still exists in countless reservoirs. This field study evaluated organic and inorganic clay-control agents to determine their effectiveness to eliminate fines (silt and clay) migration in high production-rate wells. Four gravel- packed wells that exhibited severe fines migration problems subsequent to conventional hydrofluoric acid (HF) treatments were over flushed with an organic polymeric clay-control agent. The wells were acidized again after production had significantly decreased because of fines migration and over flushed with an inorganic agent to compare their performance Descriptions of the candidate selection and design procedures are provided with the chemistry of the clay-control systems and their control mechanism.
This paper supports previous laboratory results that found organic polymeric clay-control agents are not effective in eliminating fines migration owing to mechanical dislodgment. In most cases, production declined 50 to 90% within one year following organic clay-control treatments. Additionally, the onset of water production further increased the production decline rate because of increased fines migration. Following the inorganic clay-control treatments, fines migration was greatly decreased although the wells were producing at higher rates with higher water-cuts. The oil production one year after the modified treatments was more than double the production at one year following the organic clay-control treatments. Five to six years after the inorganic fines-control treatment production was equal or higher than the one year rate following the organic clay-control treatments.
In 1991 lost time due to stuck pipe related drilling problems accounted for approximately 18% of total drilling time in Mobil Producing Nigeria Ultd.'s (MPN) offshore operations. The primary cause of stuck pipe was identified as mechanical wellbore instability. This paper presents an assessment of the mechanical stability of MPN's wells offshore Nigeria. The objectives of the study were to: 1) determine the magnitude of the in-situ principal stresses and material properties of the troublesome Intra-Biafra and Qua Iboe shale sequences; 2) quantify the drilling fluid densities required to drill mechanically stable wells through these mechanically weak formations; 3) review and recommend well planning and operational parameters which aid in minimizing wellbore stability-related drilling problems. The wellbore stability assessment was carried out with the aid of a three-dimensional computer simulation model using field derived data from a number of wells in the study area to corroborate the results. The collection and analysis of drilling data (borehole geometry and density logs, pore pressure, extended leak-off tests, local geology and other relevant well records) to determine the magnitude of the in-situ principal stresses, together with uniaxial and triaxial compressive strength measurements on formation cores are discussed. Minimum safe drilling fluid densities to promote wellbore stability as a function of well geometry and depth are presented for the most troublesome formations drilled in the study area. Implementation of the results into well planning and operations reduced wellbore stability related problems and associated trouble time to less than 5% in 1992.
Oil Mining Leases (OML) 67 and 70 lie in the southeastern portion of the Niger river delta, offshore Nigeria (Fig. 1). The leases are operated by MPN, and their joint venture partner is the Nigerian National Petroleum Corporation (NNPC). Numerous hydrocarbon-bearing structures exist within the study area, some of the largest of which are the Edop, Ubit, Oso and the Iyak fields (Fig. 2). Commercial hydrocarbons occur in sandstone reservoirs of the Miocene and Pliocene. A generalized lithostratigraphic column for the southeast Niger delta is shown in Figure 3.
The geology of the area is characterized by massive unconsolidated sands of the Pleistocene Benin Formation at surface, overlying the predominately sandy D-1 member of the Pliocene Agbada formation. Below the D-1 is the Qua Iboe member of the Agbada; predominately a weak shale which is prone to mechanical instability. Some intercalated sands are encountered toward the bottom of the Qua Iboe. The Qua Iboe is sometimes absent near onshore (northern half of OML 67/70), having been eroded. Below the Qua Iboe are found the Rubble Beds, so named due to the fact they are comprised of eroded sediments of the Upper Biafra. The Rubble Beds are also sometimes absent near onshore.