Africa (Sub-Sahara) Bowleven began drilling operations at its Zingana exploration well on the Bomono permit in Cameroon. Located 20 km northwest of Douala, Cameroon's largest city, the well will target a Paleocene (Tertiary) aged, three-way dip closed fault block. The company plans to drill the well to a depth of 2000 m and will then spud a second well in Moambe, 2 km east of Zingana. Bowleven is the operator and holds 100% interest in the license. Asia Pacific China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule. The field is located in the Yinggehai basin of the Beibu Gulf in the South China Sea and has an average water depth of 70 m. The field is currently producing 53 MMcf/D of gas and is expected to reach its peak production of 54 MMcf/D before the end of the year.
Africa (Sub-Sahara) Eni discovered gas and condensate in the Nkala Marine prospect offshore Congo. The discovery could hold from 250 MMBOE to 350 million MMBOE in place, the company said. In a production test, the Nkala Marine 1 discovery well in the Marine XII block yielded more than 10 MMcf/D of gas and condensate. Eni is the operator with a 65% interest in the block. The remaining shares are held by New Age (25%) and Societé Nationale des Pétroles du Congo (SNPC) (10%). Sonangol and Total will break ground on a deepwater oil pumping project that will increase Angola's production by more than 30,000 B/D.
Several surfactant formulations that had been tested successfully in oil-wet unconventional reservoirs were tested in mixed-wet to oil-wet unconventional reservoir cores and did not generate the expected results. To study the mechanisms of oil recovery and understand the uniqueness of these shale reservoirs, a series of studies were performed utilizing Eagle Ford (EF) and Canadian Bakken shale rocks and fluids.
In this study customized chemical formulations for improving production from the EF and the Canadian Bakken were developed. Previously related formulation development for the Bakken and Permian basins relied upon wettability alteration as the oil recovery mechanism; however, no significant oil recovery compared to brine was seen from wettability-altering formulations using EF and Canadian Bakken shale rock and fluids. Several imbibition tests showed that baseline oil recovery by brine was 20-30% of original oil in place (OOIP) for both formations. High oil recovery by brine was attributed to the mixed to water-wet nature of the pore surface. A well-connected fracture system may have also contributed. Further, there was no correlation between oil recovery and contact angle measurements.
Failure of wettability alteration as an oil recovery mechanism led to investigation of interfacial tension (IFT) reduction as an alternative mechanism. Testing this hypothesis, a change in the EF formulation reduced IFT to 0.03 dyne/cm and had oil recoveries above 60% OOIP. However, these formulations were not stable at 320 °F. Formulation KPIs were set as lowering IFT and being stable up to 320 °F. Out of many formulations tested, two containing multiple actives in a specific mixture of solvents passed the KPIs and were tested for imbibition oil recovery. A synergistic mixture had a final oil recovery above 56% OOIP as compared to 20-25% OOIP for brine alone. The imbibition oil recovery results indicate that although the ultimate oil recovery by brine alone is significant, the early oil production is significantly slower than by surfactant solutions. Upscaling the laboratory time to the field time emphasizes the value of implementing customized surfactant formulation in both early and late oil production.
Similarly, there was no correlation between wettability contact angle measurements and oil recovery for the Canadian Bakken shale. Surfactant formulations which exhibited low IFT (~0.01 dyne/cm) significantly accelerated the oil production and recovered an additional 30-45% OOIP in the tertiary mode from the imbibition tests. Further laboratory studies via the Washburn method, imbibition tests, and zeta potential measurements validated lowering IFT, not altering the wettability, as a primary oil recovery mechanism in the mixed-wet EF and Canadian Bakken.
Optimal formulations for EF and Canadian Bakken will be tested in the field by mid-2018.
An operator, seeking economies in constructing horizontal wells on pads, used a portable rig to air drill vertical holes and tangent sections to target depths of up to 8,000 ft TD, before using a larger rig to drill the curve and lateral well sections. With a 200,000 lb hookload rating, the portable rig had a depth capacity of approximately 6,000 ft using steel drill pipe (SDP). To increase the rig's depth capacity, the operator used up to 3,000 ft of aluminum alloy drill pipe (ADP) in a mixed SDP/ADP string, reducing weight and drag. Taking this approach, the operator has successfully achieved drilling objectives on 12 wells, for total savings of over $500,000 in spread cost.
The Safety and Environmental Management Systems (SEMS) rule was one of the key responses to the Macondo well blowout. The rule, which is based on API RP 75, became effective November 15th 2011.
Companies were then given two years to complete their first audits and to submit their audit reports to the Bureau of Safety and Environmental Enforcement (BSEE). There are approximately 104 operators in the Gulf of Mexico and many thousands of contractors, so the audit reports _ all of which are due November 15th 2013 _ should provide useful information as to how much progress has been made regarding the management of safety on offshore oil and gas facilities.
This paper will provide a brief timeline to do with the development of standards and regulations for offshore oil and gas facilities on the Outer Continental Shelf of the United States. Starting with the first edition of API RP 75 in the early 1990s (following the Piper Alpha catastrophe) the paper will discuss the first SEMS rule that was implemented immediately following the Deepwater Horizon/Macondo disaster. The paper will then describe the new initiatives from BSEE, including SEMS II and their Culture guidance.
The paper will also discuss some of the practical issues that operators and contractors have faced with regard to the implementation of SEMS. Topics covered include:
• Preliminary results from the audits filed with BSEE;
• The use of independent auditors as part of the audit teams;
• The role of the Center for Offshore Safety;
• The profound distinction between drilling and production when developing process safety programs; and
• The challenges to do with measuring progress with regard to offshore process safety.
Petrographic work on thin sections from rock samples collected in tight gas sandstones of the Western Canada Sedimentary basin (WCSB) shows that the sandstones are composed of intergranular, microfracture + slot, and isolated non-effective porosities. The petrographic observations of these triple porosity rocks have led to a petrophysical interpretation with the use of a triple porosity model.
Tight gas reservoirs are very complex heterogeneous systems that have been evaluated in the past mostly with single porosity models. We propose that these types of reservoirs can be better represented by triple-porosity models for more rigorous quantitative petrophysical characterization. The triple porosity model discussed in this paper fits very well the petrographic observations leading to a more rigorous characterization of effective and non-effective porosity.
The petrography and core-calibrated triple porosity model is then used for well log interpretation of those wells where these data are not available. The result is a reasonable quantitative characterization of the tight gas reservoir that can be used for improving hydraulic fracturing design, flow units determination, reservoir engineering and simulation studies. The data can be determined at room conditions and simulated conditions of net stress.
It is concluded that honoring with a triple porosity model the different types of porosities observed in thin sections and cores lead to more rigorous and useful petrophysical interpretations that can be linked to gas productivity.
Restimulation treatments have been attempted in a wide variety of reservoirs, and more than 140 papers have been published documenting the success and failure of these efforts. A database of these published examples has been compiled and analyzed to identify the mechanisms responsible for production improvement following restimulation with propped fractures (refracs). A portion of this database was recently published (Vincent 2010), and specific field examples were highlighted to demonstrate that refrac treatments can improve production by numerous mechanisms, including
This paper will briefly review restimulation attempts in six Canadian reservoirs of interest to the local audience, and will then present a more-detailed review of restimulation of horizontal wells in the unconventional Bakken oil formation. In addition to a summary of published results, this paper will introduce a significant amount of previously unpublished data regarding refrac treatments of horizontal laterals completed in the Middle Bakken. This study will identify several additional concerns and opportunities with restimulating horizontal wellbores that were not previously identified in literature reviews. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.
Restimulation treatments have been attempted in a wide variety of reservoirs, and more than 140 papers have been published documenting the success and failure of these efforts. A database of these published examples has been compiled and analyzed to identify the mechanisms responsible for production improvement following restimulation with propped fractures (refracs). A portion of this database was recently published (Vincent 2010), and specific field examples were highlighted to demonstrate that refrac treatments can improve production by numerous mechanisms including:
- Enlarged fracture geometry
- Improved pay coverage through increased fracture height in vertical wells
- Greater lateral coverage in horizontal wells or initiation of more transverse fractures
- Increased fracture conductivity compared to initial frac
- Restoration of fracture conductivity loss due to embedment, cyclic stress, proppant degradation, gel damage, scale, asphaltene precipitation, fines plugging, etc.
- Increased conductivity in previously unpropped or inadequately propped portions of fracture
- Use of more suitable fracturing fluids
- Reorientation due to stress field alterations, leading to contact of "new?? rock
This paper will briefly review restimulation attempts in six Canadian reservoirs of interest to the local audience, and will then present a more detailed review of restimulation of horizontal wells in the unconventional Bakken oil formation. In addition to a summary of published results, this paper will introduce a significant amount of previously unpublished data regarding refrac treatments of horizontal laterals completed in the Middle Bakken. This study will identify several additional concerns and opportunities with restimulating horizontal wellbores that were not previously identified in literature reviews. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.