19 Mar 2009 07:03
Hardy Oil and Gas
Preliminary Results Part 2
REVIEW OF OPERATIONS
The Company's operations in India are conducted through its wholly owned subsidiary Hardy Exploration & Production (India) Inc. (HEPI). The Company's operations in Nigeria are conducted through its wholly owned subsidiary Hardy Oil Nigeria Limited (HON).
2008 Performance
Hardy had an excellent start to 2008 with two gas discoveries on our D3 block in the KG basin and had an active operations programme planned for the remainder of the year.
At the beginning of 2008 the Company planned to drill four exploration wells, one to three appraisal wells, acquire 2,100 km2 of 3D seismic data and acquire 500 lkm of 2D seismic in India. During 2008, the Company had participated in the drilling of four exploration wells (KGV-D3-A1 and B1, GS01-S1 and M1), commenced the drilling of a development well (PY-3-D4-RL) and acquired over 1,100 km2 of 3D seismic data over the GS-01 exploration blocks.
In Nigeria the Company planned to conduct a work-over of one well and start installation of a pipeline. The Company now plans to initiate the installation of the pipeline in the second half of 2009.
The table below provides a brief comparison of our stated operational objectives for 2008 and our subsequent accomplishments through the year;
| Block | Projection | Execution |
| D3 | Drill two wells, processing and interpretation of acquired 1,200 km2 3D seismic data | Drilled two exploration wells. 3D seismic programme commenced Q109 |
| D3 | Submission of appraisal programme for Dhirubhai 39 and 41 discoveries | Appraisal programme was submitted in February 2009 to DGH for review |
| D9 | Commencement of exploration drilling programme | Drilling deferred to 2009 due to rig shortage |
| GS-01 | Drilling of three exploration wells Acquire 1,000 km2 of 3D Seismic | Drilled two exploration wells Acquired 1,165 km2 of 3D Seismic data |
| PY-3 | No operations planned | Commenced re-entry of PD-4 |
| CY-OS/2 | Commencement of appraisal drilling to assess Ganesha discovery | Revised appraisal programme and applied for an extension |
| Assam | Acquisition of 350 lkm of 2D seismic data | 2D seismic acquisition programme of 450lkm commenced in January 2009 |
| Oza | Commence field development operations | Long lead items ordered. Commencement of field operations expected in Q3 2009 |
| Atala | No operations planned | Community consultation initiated |
Competent Person's Report Update
The Company recently commissioned Gaffney, Cline & Associates Ltd (GCA) to prepare an independent technical review report on the Company's D9, D3, and Assam exploration blocks. We expect this report to be completed in the second quarter of 2009. KRISHNA GODAVARI BASIN - Eastern India
Block KG-DWN-2003/1 (D3): Exploration
(Hardy 10% interest)
Operations
The highlight of Hardy's exploration programme in 2008 was the two gas discoveries in the D3 block (Dhirubhai 39 and 41). The primary results are listed below:
KGV-D3-A1: On 13 February 2008, the Company announced the first discovery on this licence (Dhirubhai 39). The well was drilled to a depth of 1,937 m MDRT and encountered natural gas between 1,513 m and 1,597 m MDRT with a gross sand thickness of 84 m. One interval was selected for cased hole DST covering 1,565 m to 1,585 m MDRT and produced natural gas at a rate of 38.1 MMscfd through a 120/64 " choke.
KGV-D3-B1: On 1 April 2008, the Company announced a second discovery on the D3 block (Dhirubhai 41). The well encountered good quality reservoirs in the Pleistocene and Pliocene formations. MDT tests were conducted over several intervals (1,814 m to 2,101 m MDRT and 2,119 m to 2,463 m MDRT) and confirmed the presence of hydrocarbons.
The evaluation and incorporation of the data recovered from the D3 discoveries noted above is ongoing. The acquisition of a further 1,150 km2 of 3D seismic data has commenced and is expected to be complete in the first half of 2009. The drilling of the third well on the block is expected in the second half of 2009.
Appraisal: On 9 February 2009, the D3 joint venture Operating Committee reviewed and approved an appraisal programme for the evaluation of the Dhirubhai 39 and 41 gas discoveries. The proposed appraisal area comprises 750 km2 covering a large portion of the northwest corner of the block. The appraisal programme provides for the initial undertaking of various geological, geophysical and development concept studies, following which, two appraisal wells could be drilled prior to February 2011. The proposed appraisal programme has been submitted to DGH for consideration.
Background
In August 2005, Reliance and HEPI were awarded, under NELP V, a second licence in the deepwater Krishna Godavari Basin. The D3 licence encompasses an area of 3,288 km2, in water depths of 400 m to 2,100 m, and is located approximately 45 km from the east coast. Reliance is the operator.
The licence had approximately 210 km2 of existing 3D seismic data, which has been reprocessed. The A-1 and B-1 locations were identified after this data was interpreted and mapped. Under Phase - I of exploration programme, 1,930 km2 of 3D data was acquired in the year 2007. Presently, depth migration and inversion processing is being carried out on this data at GXT ION.
The various play types envisaged in this block are:
High amplitude geobody with prominent direct hydrocarbon indicators within the Pleistocene / Pliocene stratigraphic sequence.
High amplitude deep water channel complex with well preserved channel geometry within Middle Miocene/ Upper Miocene sequence
Roll over anticline within Lower Miocene / Middle Miocene sequence with concentration of high amplitude channel like depositional features at the crest.
High amplitude channel like features truncated by unconformity which provides the top and lateral seal
Deep water fan lobe on roll over anticline within Pleistocene sequence.
KRISHNA GODAVARI BASIN - Eastern India
Block KG-DWN-2001/1 (D9): Exploration
(Hardy 10% interest)
Operations
The ultra-deep-water drilling rig, "Deepwater Expedition", which is capable of drilling in waters in excess of 3,000 m, arrived in Indian waters in August 2007 and is currently operating in the KG basin. The Company has received an AFE for the drilling of an exploration well which prescribes the use of the "Deepwater Expedition" drilling rig (currently operating on the adjacent D6 block). The joint venture recently approved a budget for the fiscal year ended 31 March 2010, which provides for the drilling of one exploration well in the 2009 calendar year. The timing of commencement of drilling will remain dependent on the drilling schedule of the operator, Reliance.
Hardy has completed a review of the geological and geophysical data and interpretation completed to date and has subsequently commissioned an independent technical update of this block which is expected to be completed in the second quarter of 2009.
Background
The licence encompasses 11,605 km2 in the Bay of Bengal where water depths vary from 2,300 m to 3,100 m.
The joint venture has acquired over 4,188 km2 of 3D seismic including infill, and subsequently leads at Upper Miocene, Middle Miocene, Oligocene and Cretaceous have been identified. These leads are aerially large structural closures located toward the relatively shallower-water north-western corner of the concession, for which GIIP of many TCF has been computed by the operator. A fourth lead is a Pleistocene channel in the south eastern part of the block which is in ultra deep water with a prognosticated GIIP of a similar order of magnitude to the other leads.
Initial exploration will be focused upon amplitude anomalies within structural closure in the Miocene and Pliocene. There are many seismic anomalies within the block and, given its proximity to D6, exploration potential of this large block is regarded with considerable optimism.
GUJARAT-SAURASHTRA BASIN - Western India
Block GS-OSN-2000/1 (GS-01): Exploration
(Hardy 10% interest)
Operations
In 2008 the GS-01 joint venture drilled two exploration wells on the block and acquired additional 3D seismic.
On 26 August 2008, the Company announced that the exploratory well GS01-S1 was drilled to a total depth of 3,985 m TVDRT on the western shelf edge of the block to explore the Miocene carbonate build-up, Miocene and Oligocene reefal carbonates. While there was porosity development in the reefal carbonates, no hydrocarbons were found. The well has been plugged and abandoned.
On 3 October 2008 the Company announced that the exploratory well GS01-M1 was drilled to a total depth of 4,326 m TVDRT to explore the Oligocene and Eocene carbonate targets. Porosity development was observed in the Oligocene target but no proper seal was present. Gas shows with heavier end hydrocarbons were recorded while drilling the mid-Eocene target zone over a 20 m interval. However, the middle Eocene carbonates could not be drilled in its entirety due to BOP pressure limitations of the rig. Well logs showed reservoir development but the MDT tests were inconclusive and a conventional DST was not conducted. The well was plugged and abandoned.
Operator acquired 1,166 km2 of 3D seismic data including in fill in the north western part of the block and subsequent interpretation led to the drilling of M1 well.
The GS-01 Management Committee reviewed and adopted an appraisal programme and budget for the GS01-B1 gas and condensate discovery (Dhirubhai - 33). With an effective term through to May 2010, the appraisal area comprises 5,890 km2. The GS-01 joint venture will be making a decision on further appraisal drilling, after completion of a planned geological and geophysical review, in a few months time.
Background
The GS-01 exploration licence is located in the Gujarat-Saurashtra offshore basin off the west coast of India, NW of prolific Bombay High oil field. The original licence encompassed 8,841 km2 (5,890 km2 post relinquishment) and water depths vary between 80 m and 150 m. The joint venture has previously acquired 1,216 km2 of 3D seismic.
As announced on 15 May 2007, the Dhirubhai - 33 discovery (GS01-B1) flow-tested at a rate of 18.6 MMscfd gas with 415 stbd of condensate through a 56/64" choke at flowing tubing head pressure of 1,346 psi.
ASSAM ARAKAN BASIN - North Eastern India
Block AS-ONN-2000/1: Exploration
(Hardy 10% interest)
Operations
On 2 April 2008, Hardy announced the award of a 10% interest in the exploration licence AS-ONN-2000/1. This is the Group's first onshore block and fourth licence in partnership with Reliance. This block was offered in NELP II but commencement of operations had been delayed due to the outstanding grant of an onshore petroleum exploration licence from the appropriate state agencies.
The acquisition of 450 lkm of 2D data commenced in December 2008 and is scheduled to be completed by the second quarter of 2009. The joint venture is expected to complete the reprocessing of the existing 124 lkm 2D seismic data in 2009. Upon completion of the reprocessing and acquisition of 2D data, the phase I minimum work programme commitment for the block will be achieved.
Background
The AS-ONN-2000/1 exploration licence is located in the north eastern state of Assam, India and north of Brahmaputra River. The exploration licence covers an area of 5,754 km2 and falls within the districts of Darrang and Sonitpur. The block is in phase I of the three-phase exploration licence. Phase I (three years) will expire in the month of January 2011.
The topography of the area is primarily a plain of low relief and there is a reasonably established road network across the block. A national highway runs parallel to the river Brahmaputra and passes through the block. Different play types expected are, Anticlinal structures within Paleocene - Eocene and Gondwana, Fault closures, Pinchout/wedgeout, Fractured/weathered basement.
CAUVERY BASIN - South Eastern India
Block CY-OS 90/1 (PY-3): Producing Oil Field
(Hardy 18% interest - Operator)
Production
Actual gross field production for the year ended 31 December 2008 was 2,550 stbd (2007: 4,150 stbd). The production facilities' uptime performance was 88.2 per cent (2007: 96.8 per cent). The decrease in production is due to the conversion of well PY3-3RL into a water injection well as the well ceased to produce due to water loading. In addition, work over on well PD-4 commenced on 15 October 2008 to drill a lateral well from the existing surface location.
Production for January and February was 2,846 stbd and 2,787 stbd respectively. We anticipate that the PY-3 field will average gross daily production of 3,000 stbd for 2009. Currently the field is producing at a gross rate of 3,200 stbd.
For the year ended 31 December 2008, the average water injection rate was 7,139 bwpd (2007: 5,800 bwpd) which, at current production levels, is sufficient to maintain voidage replacement. Voidage replacement is important for maintaining pressure levels in the field that should ultimately enhance overall recovery of oil from the field. Injection facilities' uptime performance was 84.5 per cent (2007: 86.8 per cent).
The PY-3 field was shutdown twice in 2008. The first shutdown occurred between the 3rd to 12th of February 2008, due to Normor Buoy inspection and the renewal of jumper hose as per ABS requirements. The field was again shutdown from 26 November to 29 December 2008, due to the FSO loading hose, mooring hawser & back-up rope failure during tropical cyclone Nisha.
Operations
The PY3-3RL well was converted to a water injector on 23 July 2008. The current injection rate of the well is 11,350 bwpd.
As announced on 17 February 2009, the Company completed the re-entry and drilling of the PY3-PD4RL well. The PD4 vertical well was re-entered and side-tracked from 2,916 m MD (2,890 m TVDSS) and drilled down to 4,375 m MD (3,525 m TVDSS). The lateral (PR4-RL) well was drilled to increase the field production and the reservoir was expected to be encountered at 3,440m TVDSS; however the reservoir came 25 m down from the prognosis at 3,465 m TVDSS due to thickening of the overlying shale coupled with anomalous velocity variation, which is a common problem in the field. The well drilled a gross reservoir pack of 173 m MD (60 m TVD) within the reservoir section.
With the assistance of nitrogen lift, the well flowed at 700 stbd of oil with 30% water-cut, however, the well was unable to be reactivated as a self flowing well. The well has been completed as a producer with a gas lift valve to allow for future production when gas lift compression facilities are installed on the FPU.
Further drilling on PY-3 will be determined after remapping of the field has been completed incorporating the results of the PD4-RL well.
Background
The PY-3 field is located off the East Coast of India 80 km south of Pondicherry in water depths of between 40 m and 400 m. The Cauvery basin developed in the late Jurassic/early Cretaceous period and straddles the present-day East Coast of India.
The licence, which covers 81 km2, produces oil of high quality light crude (49° API). The field was developed using floating production facilities and subsea wellheads, a first for an offshore field in India.
The facility at PY-3 consists of the floating production unit, 'Tahara', and a 65,000 DWT tanker, 'Endeavor', which acts as a floating storage and offloading unit. There are four sub-sea wells tied back to Tahara. Tahara has a three-stage crude oil separation system, with the first two stages being three-phase separators and the third stage a two-phase separator. Actual liquid processing capacity on Tahara is 20,000 stbd with 17 MMscfd of gas handling capacity.
The field currently produces associated gas in the range of 3.5 MMscfd. This produced gas is used as fuel gas with excess gas being flared. The stabilised crude oil is pumped from Tahara to Endeavor for storage and offloading to shuttle tankers. Crude oil from the PY-3 field is sold to CPCL at its refinery in Nagapattinam, approximately 70 km south of the PY-3 field.
CAUVERY BASIN - South Eastern India
Block CY-OS/2: Exploration
(Hardy 75% interest - Operator)
Operations
As part of the Ganesha appraisal programme, a number of geological and geophysical studies have been undertaken, including reprocessing of the 3D seismic data covering the block to improve subsurface understanding.
The resulting reprocessing and interpretation assessment has led the Operating Committee to recommend a revision of the appraisal programme from three firm and two contingent wells to one firm well and one contingent well. The amended programme has been approved by the joint venture and reviewed by the Management Committee. The joint venture has applied for the extension of the appraisal period to January 2012. The approval is awaited from the Government of India to establish the commerciality of the non-associated gas discovery.
The joint venture has applied to the Ministry of Petroleum and Natural Gas of the Government of India to establish commerciality of the Ganesha gas discovery during an appraisal period to January 2012 as per the PSC. On 20 February 2009 HEPI received a communication from DGH to establish commerciality within 15 days or relinquish the block. We believe that this action was taken by DGH on the assumption that the Ganesha discovery was an oil discovery. As Ganesha is a non-associated gas discovery, the CY-OS/2 PSC provides for an appraisal programme to establish commerciality to January 2012. The Company is working with the Ministry and DGH to finalise the extension period.
The Company is actively considering farming out a significant portion of its participating interest in the licence.
Background
The CY-OS/2 block is located in the northern part of the Cauvery Basin immediately offshore from Pondicherry and covers approximately 859 km2. HEPI is the operator of this block.
The CY-OS/2 licence comprises two retained areas. The northern area includes the Ganesha (Fan A -1) discovery. The southern area lies immediately adjacent to the HEPI-operated PY-3 field. Another commercial gas field (PY-1) lies within the southern part of the acreage. The PY-1 field is owned by Hindustan Oil Exploration Company Limited and is expected to begin production in 2009.
Ganesha gas discovery (Fan A-1 well): On 8 January 2007 the Company announced that the Fan A-1 well had discovered hydrocarbons. On 10 August 2007, the Company announced that it would proceed with an appraisal programme to delineate the Cretaceous Fan A -1 gas discovery to establish the potential commerciality of the discovery.
NIGER DELTA BASIN - Nigeria
Block Oza (OML 11): Development
(Hardy 20% interest)
Operations
In 2008, the Oza joint venture continued to work jointly with Shell Petroleum Development Company (SPDC) towards implementing a solution on meeting applicable statutory Federal Government norms on cessation of gas flaring, which is likely to come into force in 2010.
In February 2008, Hardy Oil Nigeria Limited farmed out 20 percent of its participating interest in Oza Field to another Nigerian oil company, which has agreed to assume the responsibility of financing the first phase of the Oza Field development. The assignment was duly approved by Nigerian Federal Government on 1 August 2008.
During the year, line pipe has been acquired and has arrived in Nigeria in February 2009. Front end engineering study (FEED) and pipeline route survey commenced and final reports will be available in the first quarter of 2009. It is anticipated that pipeline construction and installation will commence in the third quarter of 2009. The Operator also successfully concluded discussions with the Oza community which culminated in the execution of an MOU.
Millenium Oil and Gas Limited, the operator for Oza field, with inputs from HON, continued efforts to obtain additional data in the field and to conclude agreements for crude handling and purchase of Oza 3D seismic with Shell Petroleum Development Company (SPDC).
Background
The Oza Field is located on-land in the north-western part of OML 11, near Port Harcourt and covers an area of 20 km2.
The Oza field is subject to a farm-out agreement between NNPC, SPDC, Elf Petroleum Nigeria Limited and AGIP as farmor and Milennium as farmee. The terms of this agreement are for an initial five year period from 27 April 2004 subject to an extension of the Oza Farm-out Agreement if approved by the Nigerian Department of Petroleum Resources (DPR).
The field has cumulatively produced approximately 1.0 MMstb from four open zones of three wells targeting three reservoirs, M5.0, L9.0 and M2.1, with the principal reservoir being M5.0. At present, Oza has three suspended wells in the field. In November 2007 the Oza joint venture successfully executed a flow test of the Oza 4 well. The flow rates averaged approximately 600 stbd of oil with a GOR of 5,466 scf/stb.
NIGER DELTA BASIN - Nigeria
Block Atala (OML 46): Development
(Hardy 20% interest)
Operations
The Atala joint venture submitted the Atala Field Development Report to the Federal Government for its review and approval. The development focuses on initially developing the oil reserves whilst exploring viable options to monetise the field's substantial natural gas potential. The Operator has been in discussions with other companies in the area to jointly evolve an approach for gas development.
The joint venture continued efforts to lease a suitable swamp barge for Atala-1 well re-entry. Preparatory work at the field location was undertaken including the completion of hydrographic survey in and around the field, tendering for dredging of well locations and engagement with the local communities for execution of MOU. The Federal government has approved the planned re-entry programme including the environmental impact assessment report. Commencement of operations will be subject to securing an appropriate swamp-barge drilling rig.
Background
Atala is located within OML 46 which is situated within a mangrove swamp on the Dodo River, a coastal area of NW Bayelsa State. The concession area is 34 km2. The Atala field was discovered in 1982 with the drilling of the Atala-1 well to a total depth of 4,058 m. Hydrocarbons were encountered and the well was cased but not tested or completed.
The Atala field is subject to a farm-out agreement between NNPC, SPDC, Elf Petroleum Nigeria Limited and Nigerian AGIP Oil Company Limited as farmor and Bayelsa as farmee. The terms of this agreement are for an initial five-year period from 27 April 2004, subject to an extension of the term of the Atala Farm-out Agreement if approved by the Nigerian Department of Petroleum Resources.