In the space of 10 months, nine horizontal production wells, with a total productive length approaching 20,600 ft and two deviated water injection wells were drilled, completed and tested from three surface cluster locations on the Abana field off Nigeria.
As part of this process, nine pilot holes were drilled to position the landing holes accurately in the reservoir, evaluate geological uncertainties, and determine near field exploration upside potential. Key processes included:
- Batch drilling: This realized savings in excess of US$11 million.
- Pilot hole appraisal: Made from one slot per cluster ahead of the planned landing sections, this process optimized the targets and resulted in one well deferral.
- Sanding analysis: This resulted in a cumulative savings of US$3.08 million.
- Real-time LWD datalink: Logging-while-drilling data transfer allowed all geosteering decisions related to the laterals to be made from London.
The wells are in the early stages of pro duction and the reservoir performance is being monitored via six surface readout (SRO) gauges installed in the completion strings. Oil production is in the range of 30,000 b/d.
Pre-drill structure map of Abana Field with planned well locations.
The Abana field is located in block OPL 230, in the Calabar river estuary, eastern Nigeria. The field was discovered by license holder Moni Pulo Ltd, and technical partner Brass Exploration (a wholly owned subsidiary of Baker Hughes) within six months of the start of the block exploration program. The field was developed and brought on stream within two years of the discovery.
The entire project, which required the installation of a complete production infrastructure, was executed within 13 months of contract award. This achievement matches or exceeds current industry performance in Nigeria.
The Abana field was discovered by two exploration wells drilled, as part of a four-well program, in the first quarter of 1997. All four wells encountered hydrocarbons. This exploration program commenced only six months from the completion of the acquisition phase of a 225-sq-km 3D seismic survey.
The first Abana field discovery well encountered a 50-ft oil column beneath a gas cap in an excellent quality reservoir interpreted to be a beach/barrier bar complex. The second Abana field well was drilled approximately 3 km along strike and intersected a 56 ft oil column in the same reservoir package. Each well produced 27° API crude at rates in excess of 3,000 b/d during drill stem tests.
Seismic section illustrating the integration of data in near real-time. This presentation was used while drilling the horizontal sections.
The reservoir interval in the first well defined a gas-oil contact (GOC) and oil-down-to (ODT) levels. The second well clearly defined an oil-water contact (OWC) in the same reservoir package, but did not define a GOC. Analysis of the repeat formation tester (RFT) and pressure-volume-temperatures (PVT) data, supported by the 3D seismic data indicated that the two wells appeared to confirm a single accumulation. PVT data and the existence of a gas cap indicated that the oil in the reservoir was at bubble point.
From the interpretation of the 3D seismic survey, the structure was defined as an elongate, four-way dip closed, rollover anticline containing two structural highs. The structure contained two tested wells with defined fluid contacts within closure.
A formal decision was made to develop the field in July 1997. Detailed planning resulted in a flexible development plan that required production via horizontal wells drilled from two surface locations. A pilot hole appraisal program and near field exploration upside evaluation were also included in the drilling sequence. A process facility delivering fully stabilized crude oil for export was to be attached to one of the clusters. Water injection for pressure maintenance of the reservoir was to be available at first oil.
With the information available from the exploration phase, the appraisal stage of the field development cycle was combined with the placement of the horizontal production wells. It was a dynamic development that required fast decision-making. Significant planning effort was spent preparing alternate scenarios in case results did not match pre-drill expectations.
The geoscience team conducted detailed evaluations to select the optimum locations for placing 10 Phase 1 horizontal production wells. Detailed reservoir simulation work further refined the drilling order, completion levels and horizontal wellbore lengths.
A 3D geological model was built to assist in the well planning and provide near real-time input into the operational decision-making process. The process was thoroughly tested to ensure the rapid assimilation of data. The interpretation of the newly acquired data allowed dynamic refinement or optimization of drilling operations and targets during the operational phase.
Reservoir simulation studies also suggested that, given the planned 7-in. completions, the only constraint on the productivity of the wells was the amount and quality of sand intersected. Consequently, provision was made to land the wells early into the structure and then drill horizontally until the well exited the reservoir. This maximized the drainage area on the field for any given well and was a change from the original thinking. Local best practice indicated that 1,500-ft laterals were appropriate.
Cost-saving analysis on the Abana Field development (Source: PPI, Houston, 1999).
The appraisal drilling was to be carried out by either deepening certain pilot holes to target deeper horizons or drilling a dedicated pilot hole. One such pilot hole was drilled to determine if a saddle existed between the structural highs drilled by the exploration wells.
As a result, appraisal and evaluation of upside potential could be assessed in a cost-effective manner and if successful, could be included in any Phase 2 development and facilities optimization planning. Both the horizontal and exploration/appraisal well locations were integrated to derive the most cost effective drilling sequence.
The data acquisition phase was planned to provide the data necessary to reduce the risk in the decision-making process and enhance the understanding of the reservoir. Coring was required to refine or validate our geological model, confirm our petrophysical parameters, and determine if sanding screens would be required in the completion string.
Sand control equipment was known to be a high-cost completion item. As such, the decision was made to quantify the critical drawdown pressure that would trigger sand production for expected fluid and gas combinations over the predicted field life.
A 3D time-slice of the Abana Field reservoir cut at the OWC, showing horizontal well locations after the development drilling campaign.
LWD data acquisition was planned from the 12 1/4-in. hole sections. Additional logs for pressure analysis and fluid sampling, sidewall coring, image logs, and VSP were to be run in the exploration tails, if successful, and in the pilot holes of the horizontal wells if required.
Installation of surface readout pressure gauges (SRO) was planned and justified for three wells per cluster. This bottomhole pressure data is required to actively manage a reservoir at the bubble point pressure for optimum production and ultimate economic recovery.
The need for water and gas injection to maintain reservoir pressure and enhance recovery was investigated. Detailed reservoir simulation work indicated that injection of water from first oil would add value to the project. Early reservoir simulation studies suggested that gas injection to maintain reservoir pressure and enhance
Detailed reservoir simulation work indicated that injection of water from first oil would add value to the project. Early reservoir simulation studies suggersed that gas injedtion to maintain pressure and enhance ultimate recovery could be economically attractive later in field life. As a result of this work, the pressure maintenance infrastructure was installed in the field and provision made for the easy installation of the gas compression equipment on the pro duction facility at the appropriate time.
The development team planned to drill landing-hole pilots to the heel of the proposed horizontal well sections. This would allow modeling of the LWD log response along the planned directional route of the landing- hole and allow us to accurately land the well at the optimal height within the hydrocarbon column. Provision was made to go to a fallback location if a minimum 50 ft oil column was not met or exceeded. Once sufficient confidence was expressed in the structural model, succeeding pilot holes could be dropped, saving time and costs.
Analysis of the oil samples taken from the exploration wells indicated that a potential problem existed with the carbon dioxide (CO2) content of the hydrocarbons. Further investigation suggested that corrosion of regular carbon steel would occur with moderate to high water cut production volumes. This finding, plus the requirement to minimize workover intervention during the life of field, resulted in the selection of 13Chrome tubulars for completion strings.
In keeping with our philosophy of minimizing well intervention during field life, gas lift mandrels and external casing packers were planned where the wellbore cut a GOC to ensure fluid isolation.
Drilling operations on the Abana field development commenced in early 1997 with the driving of the five caissons for the Abana East wells. A batch drilling approach was selected to reduce costs and enhance safety. The key components of the drilling program were batch:
- Setting of the 36 in. by 1-1/2-in. wall caissons
- Drilling to the 13-3/8-in. casing point
- Drilling of 12-1/4 -in. pilot hole appraisal holes
- Drilling of landing holes to the 9-5/8-in. casing point
- Drilling the horizontal sections and setting the 7-in. liner assembly
- Running the completions and tubing
- Testing of the wells at each cluster location.
Initially, our drilling team, Petroleum Professionals International of Houston, anticipated that using a batch drilling approach would lead to cost savings of about US$3 million. In reality, a much larger cost saving in excess of US$11 million was realized when compared to an average sequential drilling program in Nigeria.
Rig and operational efficiencies increased dramatically by having all activity focused on a small component part of each well, such as setting of 36-in. caissons or drilling 12-1/4-in. landing sections. This focus had a positive effect on timesavings as each procedure was refined with new ideas or techniques and incorporated into the drilling program.
An example of this approach was the drilling of all the pilot holes from a single slot per cluster. This technique reduced costs by cutting out the time required to nipple-up and nipple-down the diverter and blowout preventer packages, and skid the rig between well slots. It also facilitated the early appraisal of the field ahead of the landings and enabled further well optimization to take place.
Another example of this improved efficiency and learning process was combining the first two batch steps, highlighted above, into a single operation for wells drilled at the Abana West Cluster. This new procedure was used to combat the loss of soil integrity around the Abana East caissons experienced while drilling one of the Abana East tophole sections.
Directional operations in the landing and horizontal sections were also streamlined as a result of progress up the learning curve. Recognition of how certain directional bottomhole assembly (BHA) configurations worked on the Abana field significantly reduced expenditures. The increased length in actual versus planned horizontal sections also illustrates this "learning curve" process.
While drilling the first horizontal, the drilling limitations were quickly defined and optimized procedures constructed. These new procedures allowed the drilling of longer horizontals than originally planned. At the same time, drilling the longer horizontal sections could reduce the total number of wells required to fully develop the field. Additional savings were also derived from material logistics and transportation efficiencies associated with this approach. The batch process also reduced the exposure of the entire development to drilling and safety risks.
Importantly, safety risk was minimized by reducing the number of higher risk operations, such as blowout preventer and diverter handling as well as BHA make up and break down.
After consultations with other operators in the area, oil base mud (OBM) was selected for use in the drilling program. The use of this mud type saved time and improved logistics as the same mud rheology was used for all wells drilled.
From the start of the drilling campaign, a VSAT satellite communications network provided a real time logging-while-drilling (LWD) data link from the rig in Nigeria to the London office. This was a key requirement for success during the operational phase of the development. The link enabled the geoscience team to closely monitor the drilling, directional, and LWD data in real time as the wells were drilled.
It was set up in the geoscience workroom where the integrated development team and the supporting geological and geophysical data were situated. This set-up facilitated a smooth integration of the real time data into the geomodel and allowed for swift, but sound, decisions.
The logistics of communicating data and decisions was also greatly improved. As a consequence a small team of six people ran the whole geoscience operation. No wells were lost during the development program of nine production wells, two water injection wells, nine pilot holes, and two exploration tails.
Drilling operations on Abana were completed in January 1999. During the 10-month program, nine horizontal and two deviated water-injection wells were drilled, logged, completed and tested. Of the over 86,000 ft drilled on these wells, in excess of 23,200 ft was drilled horizontally. A tight true vertical depth (TVD) window of +/- 2 ft was held for most of the length of the laterals.
Of the nine pilot holes drilled, five were from the Abana East cluster and four from Abana West. Of the five drilled on Abana East, two pilots targeted an area to the northeast of the structure for the placement of a horizontal well, one combined a test for the presence of a gas cap at the structural high, and two targeted heel locations for the production laterals. Identifying the GOC at Abana East was necessary in order to optimize the position of the production lateral in the oil leg with respect to the GOC.
The pilot hole drilling from the Abana West cluster located a tighter structure with a thicker oil column than anticipated. It also defined a saddle between the two structural highs tested by the exploration wells. Based on these results, we concluded that we could drain the Abana West structure with one less horizontal well.
Two of the pilot holes, one from each cluster, were deepened to test exploration potential in deeper dip closed structures. Total footage drilled for the pilot holes and exploration tails was over 47,000 ft.
The total footage drilled during the 10-month drilling campaign on the Abana Field development was in excess of 134,000 ft and included three rig moves. Average daily footage drilled on Abana East was 438 ft per day, and 689 ft per day on Abana West. During this operation, no fishing jobs for tools or stuck pipe occurred.
Sand prediction tests were performed by IKU of Trondheim and Imperial College London on selected full-bore preserved core samples from the Abana East pilot hole. Analysis of the results indicated that sanding was not predicted until drawdowns in excess of 25 psi were encountered. Based on this analysis, the decision was made not to run sand screens in the completion strings of the horizontal wells.
If the analysis of the core for sanding potential proves to be unrepresentative of typical field conditions, then the use of 7-in. predrilled liners will allow for the retroactive installation of sand control screens. Gravel pack completions were installed in the water injection wells.
The wells are now in the early stages of production and the reservoir performance is being monitored via the six SRO gauges installed in the completion strings. The data from these gauges have indicated that while there is good evidence of aquifer support there is also a clear need for the additional pressure support provided by the water injection wells. Production is currently in the range of 30,000 b/d of oil with individual well drawdowns of 3-5 psi.
The author would like to thank Chief O.B. Lulu-Briggs, Chairman of Moni Pulo Ltd, for permission to publish and for key contributions, and recognize the major contribution of Petroleum Professionals International and the crew of Noble Drilling's jackup Don Walker.