This reports aims to analyse and discuss the drilling and completion problems, strategies, benefits and lesson learned from the two cases studies mentioned below:
"Case Study: Redevelopment of the Ebughu Field". R.A. Clark, A.A. Afemari, T.E. Ezeukwu and H. Awi, Addax Petroleum Development (Nigeria) Ltd. SPE 65199. Society of Petroleum Engineers, 2000.
"Redevelopment of a Matured Multilayered Carbonate Offshore Field Through High-Technology Horizontal and Multilateral Wells". Rajesh Kumar, SPE, S. Ramanan, SPE, and J.L. Narasimham, SPE, Oil & Natural Gas Corporation. SPE 97520-PA. Society of Petroleum Engineers, 2007.
The Redevelopment of the Ebughu Field deals with the aggressive redevelopment plan and execution carried out in a period of 10 month by Addax in the offshore Ebughu oil field located at the eastern Niger delta in Nigeria in 1999. Since its discovery in 1988, the field production was low and filled only 10% of the total capacity of the platform up to 1998. The low production rate was associated mostly to the reservoir being a thin layer containing viscous oil. In 1998, Addax started an oil field review and redevelopment plan, which increased the production from the previous 1000stb/day up to 10000stb/day in 1999, completed the platform capacity and also increased the STOIIP from 25mmstb up to 250mmstb.
This report will include the common issues of the above cases and any other considerations that may be relevant to the cases and our persective on the different situations faced by the authors.
Case Study No. 1: "Redevelopment of the Ebughu Field"
In 1980, the Ebughu oil field was discovered on a regional high of an unconformity surface called Base Qua Iboe channel, located to the east of the Niger delta in Nigeria. The field production was low and filled only 10% of the total capacity of the platform up to 1998. The low production rate was associated mostly to the reservoir being a thin layer containing viscous oil. In 1998, Addax Petroleum Development (Nigeria) Ltd became the Ebughu oil field operator after signing a PSC for 100% interest on the OPL98 license with the Nigerian National Petroleum Company (NNPC) (Figure . Ebughu Location Map).
Figure . Ebughu Location Map
Addax started inmediately an oil field review and a carried out a redevelopment plan, which took around 10 months and increased the production from the previous 1000stb/day up to 10000stb/day in 1999 (Figure . Production Performance of the Ebughu Field), completing the platform capacity and the STOIIP has been increased from 25mmstb up to 250mmstb. The assertive accelerated redevelopment execution was a key element on this success.
Figure . Production Performance of the Ebughu Field
The Ebughu field is characterised by a high quality marine environment with numerous shallow fault sequences in the sands from the Mio-Pliocene age. 6 main reservoir units were identified: AA1 to P2, AA4 A, AA4 B, AA4 C, AA4 D and AA4 E. Initial reservoir properties founded at mid rim depth of 4510 ft. true vertical depth sub-sea (TVDSS) are:
The reservoir oil rim thickness is 63ft, with a gas cap thickness between 0-440 ft, the bed dip presents between 1-3 degrees, the porosity 25-35% and the permeability 1-10 Darcy.
The normal pressure at the datum was 1961 psi and the temperature 156 Deg F and the oil is saturated.
The oil gravity is around 20o API with a viscosity of 3.4 cp and the formation volume factor 1.13 rb/stb.The gas oil ratio (GOR) was 240 scf/stb approximately and the gas gravity 0.61.
Field Development & Re-development problems
The initial development problems presented at the Ebughu field were:
Low production from the initial vertical wells. Field production provided just 10% of the platform production capacity achieved:
The main cause of the production behaviour was gas and water conification into the wells due to the high viscosity of the crude oil and the thin reservoir layer (oil rim).
Geomorphologic complexity: multiple tectonic faults, marine shales erosion from Qua Iboe Channel and uncertainty about lateral continuity:
It was unknown how close the proximity between the oil rim and the erosion surface was, due to the marging of error from the velocity model used for depth conversion.
Unconsolidated sands cause high sand production and low adherance of the cement to the formation (low - isolation).
Unknown extension of the reservoir units. Lack of data prevented accurate estimation of the reservoir boundaries and volumes.
Few or inconsistent data restricted an accurate reservoir- fluid characterisation was correlated to a wrong GOR.
Additional to the Field development problems described previously, the following problems occurred during the field re-development:
Lack of clarity as to whether the wells should have been drilled according to the direction of the reservoir units's strike (along the units) or if the wells should have been drilled in the dip direction (across the units' stratigraphy).
The lateral sand continuity was unclear. However, It was identified that the reservoir unit AA4 A and AA4 B were more prospective in terms of sand quality and AA4 C to AA4 E showed significant shale interbedding. It was defined the horizontal well as the best option to address this situation.
There were no field or reservoir characterisation reports, neither simulation data at the beginning of Addax's field review in January 1999. A core well was required to develop a robust sedimentology model.
East pilot wells needed retargeting due to the strike was out by 45o.
West pilot wells founded a higher dip and penetrated more flow units.
Random sand deposition made difficult the correlation with the stratigraphic column. It was decided to buy a 32 neighbouring wells regional study to help with this situation, but some areas encountered a higher dip and it was difficult to correlate the units due to significant shale interbedding.
Gas cap present in the AA4 D unit forced the side track of the first lateral well.
Re-development engineering solutions
Addax initiated the re-development setting up a multidisciplinary team, which leverage on its varied internal knowledge, the experts's contractor advice and involvement, and the liason with other operators, in order to generate the re-development strategy.
All raw data was catalogued, input into electronic databases and evaluated by June 1999.
Designed a phased redevelopment plan:
The first phase consisted in the appraisal and production test evaluation for the main and west Ebughu Field production.
The second phase was the Greater Ebughu appraisal by 2000 and aimed to allow the delineation of the Greater Ebughu by the appraisal of the East, North, South and Nort -East Ebughu areas.
The third phase aimed to develop the Greater Ebughu by 2001 with additional drilling commitments, if the first and second phase were succesful. Further pipelines and a new platform were to be developed if this phase was succesful as well.
Batch drilling was implemented to save time and reduce the costs. Also, real time logging with LWD Resistivity-Nuclear string (CDR-ADN) was used to measure the structural dip in real time along horizontal sections. This helped to define position of further producers' wells.
A Jack up rig with its complete crew was taken over to carry out the drilling and completion operations, due to their extensive experience and succesful records at horizontal wells drilling in a neighbouring block.
During the execution of the re-development first phase, "All in one" wells (8 Â½" horizontally drilled holes, completed with 7" slotted liner on blank pipe cemented behind an ECP in the horizontal section base) were used in wells which presented poor lateral results. Below, Figure . Ebughu Standard vs. All in One Completion.
Figure . Ebughu Standard vs. All in One Completion
In synthesis, the redevelopment benefits were:
Production increased 10 times the original due to the use of horizontal wells.
Seismic and reservoir evaluation indicated that the field size was estimated to be bigger than the original size. The STOIIP increased approximately 10 times the initial estimations due the extension of the prospective field area.
Better understanding of the reservoir and higher amount of data.
"All in one" wells were found cost effective
Proven results in a short period of time at low costs.The programme was finished in 99 days and with a cost of US$ 19.9 million, breaking several drilling records in Nigeria, there was no lost time or lost holes incidents.
Case Study Conclusions
The successful field redevelopment in just 10 month is the result of the joint knowledge from all parts involved.
The production levels and STOIIP have increased ten times their value due to the seismic and horizotal wells evaluation.
Batch Drilling and real time logging ensure a fast and agresive redevelopment strategy in the complete fied. 7 pilot wells reassure the drilling of 5 horizontal wells.
Effective drilling resources selection, drilling costs and time were reduced substantially, increasing longer section on horizontal sections, braking such drilling records in Nigeria.
The completion of an "all-in-one" completion permitted drilling and completing an 8,200ft horizontal well in 9.4 days, from a new slot and with a cost of US$2.1mm.
It can be achieved a high core recovery of the 98% in poorly consolidated sands.
Case Study No. 2: "Redevelopment of a Matured Multilayered Carbonate Offshore Field Through High-Technology Horizontal and Multilateral Wells".
In 1974 the Mumbai High field was discovered offshore, about 165 km west-northwest of Mumbai, India, at a depth of 80m in the Arabian Sea.
Its structure is that of a plunging anticline with dipping limbs across its three sides. It is also bounded by a north-northwest/south-southeast-trending fault along its east side. The Mumbai High field is divided into north and west, which are separated by an east/west shale channel. This led to the field's division to Mumbai High North (MHN) and Mumbai High South (MHS).
The reservoirs where oil and gas has been discovered were numbered from L1 to L6, however L2 and L3 are the the two main limestone oil reservoirs of the Miocene age. With L3 holding about 94% of the IOIP (initial oil in place), which is about 12,600 mmbbl.
The L3 reservoir is divided into 10 main reservoir sublayers designated as A1; A2-I to A2-VII; B and C which are separated by shales and shaley or tight limestones.
Mumbai High reached its peak production in 1990, where it started declining steeply due to reduction in pressures and the conversion of many producing wells to water injection wells.
Water injection started on the field in 1984 at MHN and 1987 at MHS. From 1997-2000 the average well production declined from 4000 BOPD/well to 650 BOPD/well. Fig 4 shows the Stratigraphy of the field.
Figure The picture on the left shows the stratigraphic sequence of the Mumbai High field, the second picture shows the sublayers in L3 reservoir
Field Development & Re-development problems
Mumbai High field was initially developed through conventional well technology, where vertical wells were used. However, due to the structural complexities of L3 the exposure was small which limited the production capacities.
Between 1998-2000 redevelopment plans were drawn to achieve further recovery. This included compiling, validating and transferring vast amounts of geoscientific data from about 700 exploratory wells that were drilled in the field.
Well logs were reprocessed using new software. The sublayers of L3 were evaluated using 3D seismic, and a new reservoir model was created.
Figure Shows the number of wells drilled per year against well type
Figure Comparison in oil production between horizontal and conventional new wells
Re-development engineering solutions
The redevelopment phase was a period of establishing and harnessing new technologies to improve the production. Several new technologies were tested in drilling mainly to improve productivity of the well and to try and reach areas that weren't accessed before. These techniques included:
Horizontal wells which increased production in the sublayers of L3
Non damaging fluids for drilling reservoir sections to prevent wellbore damage during drilling
Activation of new completions through surge plug to remove filter cake
Drilling ERD horizontal wells to reach bypassed oil areas early using existing facilities
Rotary steerable systems to minimize stuck pipe problems which in turn increases the drilling efficiency
Using glycol and low-toxicity oil-based mud (LTOBM) to drill through the Miocene shale
Use of logging while drilling (LWD)
Other initiatives for redevelopment of brown field included:
Establishment of virtual reality center for visualizing the subsurface features in an immerse environment in real-time operation mode so as to better understand reservoir complexities by integrating seismic and well data. This was used to improve well placement.
Restoring aging surface facilities; reducing the process system bottleneck; and reduction in back-pressure of wells as own oil recovery (OOR) measures and continuous gas lift optimization.
Use of Solid Expandable Tubular (SET) and Whipstock Technology, which was used to drill horizontal sidetracks in the lower layers of L3
About 76% of the wells drilled were horizontal, and 12% as ERD/ERD horizontal/multilateral.
The horizontal drilling technology has showed a significant improvement in well productivity.
As for the brownfield development/ rehabilitation the following was observed:
Horizontal sidetracks from existing wells ledt to significant production increase
The process is useful in planning brownfield development programmes
These sidetracks are starting to replace most of the conventional remedial workovers and have resulted in an increased OOR
SET technology used with a few wells which resulted in a high water cut well.
Whipstock technology that was used reduced the well completion times.
By 2000 production increased to 52000 BOPD in MHN
Production reached to 270,000 BOPD through 580 producers
Maintaining the water production from the field has been very successful due to new wells and sidetracks in bypassed oil areas.
By March 2005, 21.6% of IOIP has been recovered; out of which 20.4% was from L3
Table showing process and techniques used during redevelopment
Figure Graph showing production development before and after redevelopment
Case Study Conclussions
The plans to redevelop the field with high technology drilling such as horizontal/multilateral drilling have rejuvenated the field.
L3 reservoir responded positively to the redevelopment methods, as these technologies were able to access the tightest sub layers, where they were found to be more productive.
Geological and geophysical data came in to be very important and useful in planning high-technology wells across the field.
On one hand the cases studiedâ€¦
On the other handâ€¦
We may conclude that the existance of quality controlled data is vital for the success of any development or redevelopment. Batch drilling has been proven as an efficient method to drill several wells at lower costs and in lesser time than consecutive wells.The seismic results and real time well logging proven valuable to the areal extensions of the reservoir and the delineatioon of the volumetric model.