Drilling optimization and drilling time reduction is a challenging and crucial task for many operators and service providers.
This paper describes how multidiscipline team of drilling contractor and service provider have maximized drilling performance and significantly reduced drilling time in the Valanginian horizontal wells at the Samburgskoye field in the northern part of Western Siberia by adopting a new technology and employing engineered drilling system (EDS) approach.
Commercial hydrocarbon production in the Samburgskoye field started in April 2012 by putting two gas treatment trains into operation. A launch of the third train was rescheduled from 2015 to the 2014 to accelerate field production. Updated drilling plan required to drill long sidetrack horizontals on oilfield from small rigs with limited capabilities where use of a conventional rotary steerable technology was restrained. New generation of rotary steerable technology and drill bits that specially designed for the specific technology and application were used to achieve objectives for drilling campaign. Drilling fluid properties were optimized to fit the desired equivalent circulation density and for formation damage control.
The latest development of a motorized push-the-bit rotary steerable system (RSS) enabled the drilling contractor to achieve more than 1300 m of meterage drilled in a 50-hour period on a sidetrack well – longest horizontal sidetrack on the oilfield. Use of the custom-designed engineered drilling system based on the recently developed RSS increased efficiency and resulted in significant monetary savings by reducing well construction time by an average of 25 days. Results for daily meterage showed increase by 300% and mechanical speed by 400% comparing to average results achieved previously on oilfield with conventional bottom hole assemblies. Implementation of the EDS approach led to unique results enabling use of new technologies on variety of rigs where it was not possible to explore the benefits of RSS technology before and drill to planned total depth in harsh drilling environment with high levels of downhole torsional vibrations.
This paper will describe how multidisciplinary well design and construction team addressed challenges in drilling of Valaginian horizontal wells in the Samburg field, North of Western Siberia. Achieved results of new approach for complex technical projects will be presented and other distinctive features of recently developed RSS systems will be described.
Dobrokhleb, P. (Schlumberger) | Kretsul, V. (Schlumberger) | Dymov, S. (Schlumberger) | Razumniy, M. (Schlumberger) | Ablaev, A. (Schlumberger) | Milenkiy, A. (JSC Arcticgas) | Tarasov, O. (JSC Arcticgas)
The Achimov formation of the Urengoy field are considered as a promising object that by 2020 will be able to provide about 10% of gas production in Russia. Because of the complex geological conditions and a high accident rate while horizontal drilling, deposit is mostly developed by S-shaped wells. In 2013 a number of new technologies and engineering solutions in the intervals penetrated into the Achimov deposits, has allowed to drill the first time successful well with the 1000 m horizontal section length. As a result of further optimization and implementation of new solutions for each interval of the well, it was able to significantly reduce construction time and increase economic efficiency of drilling.
By collaborative efforts of the field operator, drilling contractor and oilfield services company was developed and optimized a drilling system for horizontal wells in the Achimov deposits, which included complex engineering solutions, technologies and workflows. Based on the geomechanical model was optimized drilling fluids density and rheological properties for each well section, as well as designed optimal well trajectories. For drilling performance increase there were introduced new bottomhole assemblies (BHA) with rotary steerable systems combined with positive displacement motors (PDM), selected their optimal combinations with new polycrystalline diamond (PDC) bits. With the use of a drilling process simulation package were selected optimal drilling regimes. To eliminate inefficient operations and risk mitigation, selection and evaluation of drilling and completion decisions were made within a single system.
As a result, optimization of entire drilling system, allowed to increase drilling rate in the intervals of production and liner section more than two times through the increase of ROP, number of trips reduction and flat time optimization. Application of RSS in combination with PDM section, selection of its pair with PDC bit, application of oil based mud (OBM) with a lubricant, as well as the implementation of measures aimed at keeping wellbore in a stable state and effective hole cleaning practices, that helped to reduce BHA vibrations, stick and slip of BHA while drilling and increase rate of penetration (ROP) by 59-100%, and increase the service life of BHA components. Thus achieved the ability to drill each interval per one run. The average well construction time decreased by 30%, and the fastest well was delivered to the customer by more than 2 times quiker ahead of a plan. The implementation of this approach afforded to remove restrictions associated with complecations of horizontal drilling and introduce new options for their completion, allowing to increase productivity.
As an experimental industrial tests on several wells was conducted a multi-stage hydraulic fracturing, the results significantly exceeded the previously achievable performance on initial flow rate. As a result, the operator revised its approach to the development of its license area in favor of horizontal wells, which offer a great promise in terms of improving efficiency of the deposits reserves development, as well as perspective of trial and introduction of new advanced technologies and solutions of well construction in Russia.
Bourdarot, Gilles (ADMA-OPCO) | Khemissa, Hocine (ADMA-OPCO) | Al Shemsi, Abdullah (ADMA-OPCO) | Murat, Bruno (Beicip-Franlab) | Richet, Remy (Beicip-Franlab) | Games, Federico (Beicip-Franlab) | Porcher, Florent (Beicip-Franlab)
During this innovative work a 3D Stratigraphic forward Modeler initially designed for geohistorical basin modelling has been used to produce multi-realization of 3D facies distribution of a giant offshore carbonate reservoir in Abu-Dhabi.
The Stratigraphic 3D forward Modeler simulates carbonate production and transport by solving a diffusion equation. The modeling started from a given age, through a sequence time steps. At each time step, three main parameters controlling deposits are modelled: 1) Accommodation space which reflecting the total available water depth for sediment deposits, 2) Sediment Supply by setting carbonates production laws inside the model, 3) Transport and Wave Reworking using a diffusion law, function of wave energy, slope and a diffusion coefficient depending on carbonate nature and grain size.
The model is calibrated to facies thickness and texture described at 17 cored wells by a previous 4th order Sequence Stratigraphic Sedimentology study.
The model has a grid of 200 X 200m, similar to the reservoir simulation grid size, a 50,000 years time step which corresponds to 136 layers, ensuring a vertical resolution in the range of 1 to 2 meters. The total size of the model is 2.7 Million cells. The resulting model reproduces the spatial facies distribution in the reservoir and with more than 80% success the facies texture and thickness at cored wells for each 4th order sequences.
By varying the parameters controlling sediment deposits, using an Experimental Design approach, several realizations of the geological model have been produced to capture uncertainties on facies distribution between wells, each of them honoring the facies description and thickness at cored wells.
This new approach increases considerably the consistency, resolution and reliability of the geological model between wells.
3D stratigraphic forward modeling is used since 1992 in order to help petroleum geologists to quantify the sedimentary architecture of a basin, in 3D, both in siliciclastic and carbonate environments (Grangeon1,2, Doligez3).
The main principle of 3D stratigraphic forward modeling is to simulate the paleostratigraphic evolution of the basin geography through time, using long-term (T=100's kyr - 10's Myr) and large-scale (L=10 - 100's km) sediment transport equations. Application of mass balance principle allows to define sedimentation or erosion rate at each point of the basin and at each time and thus, to simulate progressively the basin deformation and filling, and to quantify in 3D the sedimentary architecture.
At exploration and appraisal scales, petroleum geologists are usually using such a tool to define facies distribution, reservoir thickness, connectivity in an unexplored area or along a future appraisal well, to build a 3D geometrical and facies model of a basin, in order to locate possible fields .
Yudin, A. (Schlumberger) | Tarakanov, I. (Schlumberger) | Klyubin, A. (Schlumberger) | Ablaev, A. (Schlumberger) | Zharikov, M. (Gazprom Dobycha Urengoy) | Vashkevich, A. (Gazprom Dobycha Urengoy) | Yaskin, I. (Gazprom Dobycha Urengoy) | Sabirov, L. (Gazprom Dobycha Urengoy)
This paper was prepared for presentation at the Young Professional Session of the SPE Russian Oil and Gas Exploration and Production Technical Conference and Exhibition held in Moscow, Russia, 14–16 October 2014.
In the Urengoyskoe field, Russia, the Achimov deposits are found at depths of nearly 4000 m and feature a more complex geological structure when compared to the Cenomanian and the Valanginian deposits. Furthermore, the Achimov deposits feature abnormally high formation pressure (over 600 bar) and are characterized by a multiphase state of hydrocarbons. To achieve economic well production, performing stimulation treatments in the Achimov formation of Urengoyskoe gas condensate field is required.
Hydraulic fracturing proved to be a reliable method for increasing well productivity from the Achimov formation by a factor of 2.5; however, well completion restrictions allow for placing only small-size proppant mesh. Proppant fracturing treatments are conducted with high-polymer loading to ensure fluid stability at high formation temperatures, which leads to further reduction of fracture cleanup efficiency. These effects reduce the effective half-length and compromise the full production potential.
New channel fracturing technology that creates open-flow channels inside the proppant pack was selected to improve production. Channels are created by pulsating proppant at surface. Pulses with proppant are separated by pulses of clean fluid, which creates proppant clusters inside the fracture, holding the walls of the fracture open. Fracture cleanup is conducted through channels without restrictions to fluid and polymer flowback. Thus, the channels improve effective fracture half-length and, consequently, gas condensate rates. The increased drainage area also improves hydrocarbon recovery.
Previously in Russia, channel fracturing was used primarily in oil fields. The largest gas operator in Russia has initiated an extensive pilot campaign for channel fracturing in new areas of the Urengoyskoe field. To date, seven wells have been successfully completed with channel fracturing, leading to a significantly higher productivity of 30% versus offset conventionally stimulated wells and lower drawdown.
The production focus has shifted from the easy-to-access, shallow, gas-bearing deposits in the Cenomanian and Valanginian of the Urengoyskoye Field to the deeper, tight, gas-condensate formations in the Achimov. Several different operators have started to develop the Achimov formation with different development strategies on over eleven license blocks; however, with the common objective to maximize liquid and gas production from their license. Based on a couple of pilot projects with extensive testing, a unified development plan over the entire Achimov formation had been devised before the development start-up to guarantee hydro-carbon recovery and guide the operators through the development. Due to the enormous challenges encountered in the Achimov formation such as high pressure, low formation quality and deviated well stability challenges, the initial unified development plan foresaw the drilling of simple production pattern with a large amount of vertical wells. However, since the instigation of the unified strategy, the technology has advanced to overcome most of the challenges encountered in the Achimov formation with the potential of improving the sub-optimal, original development plan.
This paper discusses the general challenges of the Achimov development from well construction, production operations to reservoir management encountered by the various operators and attempts to define integrated solutions chains to overcome those. The operational and financial impact of the various technologies of the solution chains is defined and a possible roadmap for field development is devised. Several different operators have started to develop the Achimov formation with different development strategies on over eleven license blocks.
Bockstedt, a mature oilfield in Northern Germany, was discovered in 1954 and put on-stream in the same year. The waterflooding of this high permeability Valanginian sandstone reservoir, with moderately viscous oil and highly saline brine was started in 1959 and continues to date, albeit at a high watercut. A compartment within this field was selected for a pilot test of the biopolymer Schizophyllan; a polysaccharide, with considerable viscosifying efficiency and high salinity and temperature stability.
As the biopolymer flood progresses, surveillance and monitoring techniques that estimate in-situ polymer properties and help to understand the influence of the polymer on reservoir performance are applied. Operational procedures have also been developed and tested to ensure a manageable restart of operations in the event of planned and unplanned well shut-ins. Production logging test runs in the injection well during the water injection phase showed a homogeneous injection profile over the reservoir interval. Well logs from new wells drilled within the pilot area provide additional insight with regards to the saturation distribution. Passive and partitioning tracers have been injected and are regularly being sampled and analysed.
After a successful polymer injectivity field test was conducted in mid-December 2012 for Schizophyllan, continuous polymer injection commenced in early January 2013. High-resolution data available from permanent downhole gauges show an initial increase and subsequent stabilization of bottom-hole pressure at a higher value in the injection well after the start polymer injection. A modified Hall plot used to assess the polymer injectivity does not show any significant reduction in injectivity. An estimation of the reservoir properties during the water injection phase and subsequently the in-situ effective polymer viscosity during the polymer injection phase using several falloff tests confirms that, the polymer is not shear degraded in the reservoir and offers insight as to the position of the polymer front in the reservoir. The work was accompanied by numerical simulation to better understand the in-situ rheological properties of the polymer.
This paper discusses the challenges, experiences and early results from the operational aspects of an on-going polymer flood pilot in a mature oilfield after an early technical evaluation.
Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.
A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.
Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.
This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.
The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
Yushkov, Anton (THK-BP) | Romanov, A.S. (THK-BP) | Mukminov, I.R. R. (THK-BP) | Ignatiev, A.E. (THK-BP) | Romashkin, S.V. (THK-BP) | Buchinsky, S.V. (THK-BP) | Glumov, D.N. (THK-BP) | Magdieva, L.K. (THK-BP)
Using BU161-4 formation of the Urengoy oil and condensate field deposit as an example the authors have demonstrated that today in the absence of developed transport infrastructure high CAPEX and OPEX investments are inevitable. It will result in negative economic results in developing oil banks in gas and condensate deposits located in the Northern and Polar regions of the Russian Federation. This factor decreases attraction of such assets for investors significantly and actually oil reserves in oil banks and gas reserves in gas caps are not developed and it is uncertain when these reserves might be developed. As a result the state will get less revenue from developing hydrocarbon reserves.
A large portion of the resources potential of the Russian Federation Polar regions is provided by natural gas and condensate and oil and condensate fields. Deposits with oil banks could be found in the geological cross section of these fields. At that hydrocarbon resources in the gas cap (estimated in tons of oil equivalent) are significantly larger then oil reserves in the oil banks. It is assumed that identical deposits would be located in the Arctic offshore.
Having insignificant oil reserves (keeping in mind that the circumpolar region is not developed) gas and condensate reserves will represent key economic value. Economic evaluation results of some projects in Yamalo-Nenets Autonomous District (YANAO) have demonstrated that development of oil banks is not profitable as a rule or it is on the brink of profitability.
Reasons for negative economic efficiency of developing oil banks in the circumpolar region deposits versus deposits in regions which are developed are presented below:
1. High expenses for transporting oil.
2. Higher cost of wells and equipment. It is explained by location in remote areas and climate conditions.
3. Low technological efficiency of developing the deposits. It is explained by insignificant thickness of oil banks and gas breakthrough, additional expenses for a gaslift and well heating, etc.
4. Relatively small oil reserves in the formation and as a result low production rates.
5. Additional expenses for utilization of the associated gas.
It is obvious that economic attraction of the "gas?? and "oil?? portion of such assets will depend upon the situation in the hydrocarbon market in the nearest 10-20 years and the situation in the development of Polar region. As of today on land Polar region infrastructure in the Russian Federation is targeted to produce and transport gas and condensate. Below it will be demonstrated that development of a gas cap without developing oil bank in the current situation is the most attractive option for the License holder and the State as well.
Deep marine basin floor channel and basin floor fan (bff) complexes are well developed in the third order Barremian (9A) to Aptian (13B) sequences in the Bredasdorp Basin, offshore the Southern Cape of South Africa. The bff com-plexes contain stratigraphically and structurally trapped hydrocarbons, within moderate to good reservoir quality turbidite channel sandstones. The Sable oil and gas fields are reservoired within the upper part of this turbidite system.
The sequences fall within a stage of early drift history with a progressively enlarging basin that flooded and integrated the initial post-rift embayments with connections to the proto- Indian Ocean. Deposition of well-defined systems tracts together with associated type1 erosional unconformities developed. The third-order (onlap-fill) sequences reflect both thermal subsidence along the ba-sin axis and episodes of re-activated faulting. Generalized facies distributions, determined from log patterns, core data and maximum grain size data have assisted in generating geological models for the region. Poorer quality channel overbank and sheet sand (distal fan) deposits are not resolvable from seismic and geological models must take this into account so that allowances can be made for these 'invisible' volumes.
Ideally, bff systems should be radial in shape but because deposition occurred in the relatively confined Bredasdorp Basin their shape is controlled by the ba-sin topography and as such are predominantly elongated.
The provenance for these sandstones consisted of Table Mountain quartzites and Cape granites sourced from the mainland and the Agulhas Arch. The ba-sin maintained it's strong northwest - southeast elongation, inherited from the synrift sub-basins and was open to relatively free marine circulation to the southeast with the Southern Outeniqua Basin and the Indian Ocean. Sedimen-tation into the Bredasdorp Basin thus occurred predominantly down the axis of the basin with main input direction from the west.
The Bredasdorp Basin, located on the southern continental margin off the coast of South Africa is mostly filled by marine Aptian to Maastrichtian deposits, which were deposited on pre-existing Late Jurassic to Early Cretaceous fluvial and shallow marine synrift deposits.
Drilling for hydrocarbons in the Bredasdorp Basin commenced in 1973, leading to the discovery in 1980 of the F-A gas field in the Berriasian to Valanginian shallow marine synrift sandstones along the northern flank of the basin (Figure 1). Further discoveries led to the gas-to-liquids (GTL) project at Mossel Bay commissioned in 1992, which produces syn-fuels from gas and condensate production from the F-A and E-M fields. Most recently the South Coast Gas Project (SCG) has been ratified to make available several central basin Barremian (9A) to Aptian (13B) gas and condensate discoveries in order to sustain and extend production of syn-fuels at the GTL plant. The generally thin pre-Aptian central basin gas charged reservoirs, confined to narrow channels, have proven to be a challenge to model, both geologically and commercially and their contribution to the basin's success will soon be realised.
The paper presents the results of an integrated study comprising different disciplines and scales (core, log and seismic). The study followed the drilling of a well through a Jurassic carbonate reservoir in a NE-SW direction, which was cored near the tip of a NW-SE striking fault. Core and FMI data show a number of open and closed fractures, all striking in a NW-SE direction, contrary to what was expected from the regional structural model.
The structure grew through the Mesozoic with NE-SW extension producing a set of NW-SE striking normal faults and related fractures. A pulse of growth occurred during the Late Cretaceous-Tertiary, followed by continued Tertiary growth. 3D seismic data clearly shows the Lower Cretaceous fault pattern. The faults decrease in throw with depth, and only a limited number cut the Jurassic.
Interference tests show a preferential NE-SW communication pathway between wells. In addition, borehole and core data from other wells show open fractures, which tend to have a NE-SW strike, and a second set of closed fractures orthogonal to these.
The following were concluded from a review of the data:
Correlation between core goniometry and FMI image analysis is excellent.
The well is located near the tip of a NW-SE striking fault, and is likely to be in the transfer zone between two faults.
Two sets of fractures occur in the Jurassic. A fault related NW-SE striking set and a NNE-SSW striking set occurring further away from faults.
Fractures occur as near vertical, broken non-mineralized, and completely healed; and tend to occur in swarms.
Fractures in the reservoir are likely to provide additional permeability.
To intersect the maximum number of open fractures in the Jurassic, wells should be horizontal and oriented WNW-ESE away from faults and NE-SW close to faults.
Introduction and Objectives
The oil well OAD-1 (Offshore Abu Dhabi-1) lies in the northern sector of a major Field located in the central part of the Arabian Gulf. The Field is a gentle, slightly asymmetric domal anticline. Oil and gas have been produced from the Lower Cretaceous, Upper and Middle Jurassic, and Permian. The Upper Jurassic Arab reservoirs are the main oil producing reservoirs.
The Lower Cretaceous Upper Thamama is a highly faulted and fractured carbonate reservoir. The underlying Arab reservoirs are separated from the Thamama by the Hith anhydrite Formation.
The faults in the Arab Formation appear to be vertical continuations of four faults in the Thamama Formation with only the largest faults in the Thamama Formation extending down into the Arab Formation. This indicates that the Hith Formation represents a significant boundary to fault propagation, and therefore probably to fluid flow. There may be mechanical stratigraphy in the Field, with different deformation styles in the different stratigraphic units.
The OAD-1 well was drilled in close proximity to a NW-SE striking normal fault (Fig. 1) as a producer from the Arab D reservoir. Some 140 feet of core were cut and recovered from the Arab D reservoir. The core indicated a large number of open and closed mineralised fractures. A formation micro image log FMI was recorded across the interval and also revealed a number of fractures.
The objective of this paper is to present the results of an integrated study of the fractures encountered in this well.
The structural setting and stratigraphy are reviewed followed by the details of fracture description and comparison with FMI log data. Implications of fractures in the Arab D are also discussed.