Tar mats at the oil-water contact (OWC tar mats) in oilfield reservoirs can have enormous, pernicious effects on production due to possibly preventing of any natural water drive and precluding any effectiveness of water injectors into aquifers. In spite of this potentially huge impact, tar mat formation is only now being resolved and integrated within advanced asphaltene science. Herein, we describe a very different type of tar mat which we refer to as a "rapid-destabilization tar mat??; it is the asphaltenes that undergo rapid destabilization. To our knowledge, this is the first paper to describe such rapid-destabilization tar mats at least in this context. Rapid-destabilization tar mats can be formed at the crest of the reservoir, generally not at the OWC and can introduce their own set of problems in production. Most importantly, rapid-destabilization tar mats can be porous and permeable, unlike the OWC tar mats. The rapid-destabilization tar mat can undergo plastic flow under standard production conditions rather unlike the OWC tar mat. As its name implies, the rapid-destabilization tar mat can form in very young reservoirs in which thermodynamic disequilibrium in the oil column prevails, while the OWC tar mats generally take longer (geologic) time to form and are often associated with thermodynamically equilibrated oil columns. Here, we describe extensive data sets on rapid-destabilization tar mats in two adjacent reservoirs. The surprising properties of these rapid-destabilization tar mats are redundantly confirmed in many different ways. All components of the processes forming rapid-destabilization tar mats are shown to be consistent with powerful new developments in asphaltene science, specifically with the development of the first equation of state for asphaltene gradients, the Flory-Huggins-Zuo Equation, which has been enabled by the resolution of asphaltene nanostructures in crude oil codified in the Yen-Mullins Model. Rapid-destabilization tar mats represent one extreme while the OWC tar mats represent the polar opposite extreme. In the future, occurrences of tar in reservoirs can be better understood within the context of these two end members tar mats. In addition, two reservoirs in the same minibasin show the same behavior. This important observation allows fluid analysis in wells in one reservoir to indicate likely issues in other reservoirs in the same basin.
Hassan, Hany Mohamed (Petroleum Development Oman) | Al-hattali, Ahmed Salim (Petroleum Development Oman) | Al Nabhani, Salim Hamed (Petroleum Development Oman) | Al Kalbani, Ammar (Petroleum Development Oman) | Al Hattali, Ahmed (Petroleum Development Oman) | Rubaiey, Faisal (Petroleum Development Oman) | Al Marhoon, Nadhal Omar (Petroleum Development Oman) | Al-Hashami, Ahmed (Petroleum Deveopment Oman)
A cluster area "H" consists of 4 carbonate gas fields producing dry gas from N-A reservoir in the Northern area of Oman. These fields are producing with different maturity levels since 1968. An FDP study was done in 2006 which proposed drilling of 7 additional vertical wells beside the already existing 5 wells to develop the reserves and enhance gas production from the fields. The FDP well planning was based on a seismic amplitude "QI" study that recommended drilling the areas with high amplitudes as an indication for gas presence, and it ignored the low amplitude areas even if it is structurally high. A follow up study was conducted in 2010 for "H" area fields using the same seismic data and the well data drilled post FDP. The new static and dynamic work revealed the wrong aspect of the 2006 QI study, and proved with evidence from well logs and production data that low seismic amplitudes in high structural areas have sweet spots of good reservoir quality rock. This has led to changing the old appraisal strategy and planning more wells in low amplitude areas with high structure and hence discovering new blocks that increased the reserves of the fields.
Furthermore, water production in these fields started much earlier than FDP expectation. The subsurface team have integrated deeply with the operation team and started a project to find new solutions to handle the water production and enhance the gas rate. The subsurface team also started drilling horizontal wells in the fields to increase the UR, delay the water production and also reduce the wells total CAPEX by drilling less horizontal wells compared to many vertical as they have higher production and recovery. These subsurface and surface activities have successfully helped to stabilize and increase the production of "H" area cluster by developing more reserves and handling the water production.
Significant advances have been made in formation testing since the introduction of wireline pumpout testers (WLPT), particularly with respect to downhole fluid compositional measurements. Optical sensors and the use of spectroscopic methods have been developed to improve sample quality and minimize sampling time in downhole environments. As a laboratory technique, spectroscopy is a ubiquitous and powerful technology that has been used worldwide for decades to measure the physical and chemical properties of many materials, including petroleum, geological, and hydrological samples. However, laboratory-grade, high-resolution spectrometers are incompatible with the hostile environments encountered downhole, at wellheads, and on pipelines. Only limited resolution techniques are available for the rugged conditions of the oil field. This paper introduces a new optical technology that can provide high-resolution, laboratory-quality analyses in harsh oilfield environments.
A new technology for optical sensing, multivariate optical computing (MOC), has been developed and is a non-spectroscopic technique. This new sensing method uses an integrated computation element (ICE) to combine the power and accuracy of high-resolution, laboratory-quality spectrometers with the ruggedness and simplicity of photometers. Many modern sensors typically merge the sensor with the electronics on an integrated computing chip to perform complex computations, resulting in an elegant yet simplistic design. Now, optical sensing using ICE features an analogue optical computation device to provide a direct, simple, and powerful mathematical computation on the optical information, completely within the optical domain. Because the entire optical range of interest is used without dispersing the light spectrum, the measurements are obtained instantly and rival laboratory-quality results.
A proof of concept MOC with ICE has been demonstrated, logging more than 7,000 hours, in nearly continuous use for 14 months. Oils with gravities ranging from 14 to 65°API have been measured in downhole environments that range from 3,000 to 20,000 psi, and from 150 to 350°F. Hydrocarbon composition measurements, including saturates, aromatics, resins, asphaltenes, methane, and ethane, have been demonstrated using the MOC configuration. As compositional calculations therein, GOR and density are validated to within 14 scf/bbl and 1%, respectively. The paper discusses the details of the new ICE-based sensor and describes its adaptations to downhole applications.
Stoupakova, A.V. (Moscow State University) | Kirykhina, T.A. (Moscow State University) | Suslova, A.A. (Moscow State University) | Kirykhina, N.M. (Moscow State University) | Sautkin, R.S. (Moscow State University) | Bordunov, S.I. (Moscow State University)
The Russian Western Arctic Basins cover the huge area including the Barentsand Kara seas, the western part of the Laptev sea and adjacent territories withsome archipelagoes and islands (Spitsbergen, Franz Josef Land, SevernayaZemlya, Novaya Zemlya, etc.). They comprise the Barents and Kara Basins, thenorthern areas of the Timan-Pechora Basin, the North West Siberia, includingYamal and Gidan peninsulas and the Yenisey-Khatanga Basin. Within the RussianWestern Arctic basins the following main tectonic elements can be identified:extensional depressions (Central-Barents, Yenisei-Khatanga, West Siberia, EastUrals) with sedimentary thickness is more than 12- 14 km; platform massiveswith average thickness of sediments of 4 - 6 km, monoclines and tectonic steps,like transition zones between extensional depressions and platform massives.Western Arctic basins are filled by mainly Palaeozoic and Mesozoic sedimentarysuccessions. In the sedimentary cover of this large region, many commonstratigraphic complexes and unconformities can be traced within Palaeozoic andMesozoic complexes that show similarity of geological conditions of theirformation. Analysis of the Russian Western Arctic basins, their structures andhydrocarbon prosepctivity shows the areas, which are favourable for hydrocarbonaccumulations. Deep depressions, as areas of long-term and stable sinking, arehighly promising zones for the accumulation of predominantly gas fields. Theyform regional gas accumulation belts, extending for thousands of kilometres,where the largest fields can be expected in the zones of their intersectionwith the major tectonic elements of another strike. Within the Barents-Karashelf, the large belt of predominantly gas accumulation extends from the northof the West Siberian province through the South Kara basin and into the BarentsSea. The second potential belt of predominantly gas accumulation may beassociated with the North Barents ultra-deep depression. On the flanks of thedepressions the sedimentary cover profile does not contain the complete set ofoil-and-gas-bearing complexes, identified in the central parts of theextensional depressions. The reservoirs can be filled by HC due to the lateralmigration of fluids from the neighbouring kitchens or from their own dominantoil-and-gas source rock strata. For the formation of oil accumulations, themost favourable are platform massifs and ancient uplifts areas.
This paper will describe the state of art in active acoustic detection ofoil and gas in the water volume as well as the seafloor. Examples of real datawill be described with the relevance to the leakage detection challenges wheresurveillance and early detection is crucial. Active acoustic data will bepresented from several trials from various parts of the world, examples hereofis California natural seeps, Brazil leakage detection, Norway plume mixingphenomenon's and more.
Applications: Leakage detection on subsea assets, Site surveys of leakages,Oil response capabilities, Oil recovery capabilities, Dispersant efficiencyespecially sub surface, Quantification of leak flux both gas and fluid.
Results, Observations, and Conclusions: Expedition results will be reviewedbased on several real life tests and deployments of active acoustic systems.Conclusion of expected performance of active acoustic systems will be drawn.Miniaturization and adaptation of power requirement as well as uplink demand,combined with sufficient processing to avoid false alarms will bediscussed.
Significance of Subject Matter: Early subsea leakage detection is absolutelykey to any arctic project, quantifiable flux rates is an important key input toall decision-making during operation of oil fields in all regions.
The Mackenzie Delta in Canada's Northwest Territories hosts manypermafrost-related gas hydrate accumulations that were indirectly discovered orinferred from conventional hydrocarbon exploration programs. In particular, gashydrate intervals characterized with high saturation show high resistivity andhigh P- and S-wave velocity on well-log data, and are typically found insand-rich horizons. As demonstrated at the Mallik site, the velocity contrastbetween highly saturated gas hydrate-bearing sediments and unconsolidatedwater-bearing sediments is significant and allows their detection with seismicdata. Here, we use 2D and 3D seismic reflection data acquired by industry onRichards Island to map and characterize gas hydrate accumulations beneath athick permafrost area of the Mackenzie Delta. Specifically, we show new seismicevidences of gas hydrate accumulations near YaYa, Ivik and Umiak. The presenceof gas hydrate was previously inferred from well-log data in several boreholeslocated in those areas. All seismic data were re-processed following anAVO-friendly flow that preserved relative amplitude relationships. On suchdata, the strong acoustic impedance of gas hydrate produces strong amplitudeseismic reflections. The seismic signature of gas hydrates is confirmed byseismic-to-well correlation in areas where boreholes are available. Resultsindicate that gas hydrate accumulations occur in structurally-controlled playstypical of conventional oil and gas traps found in this area, and furtherdemonstrate that gas hydrates are part of the regional petroleum system.
The compact Arctic Ocean region is the last major hydrocarbon frontier areain the Northern Hemisphere and may possibly be the single richest natural gashydrate (NGH) province on Earth. Because of the extreme weathering and erosionconditions associated with the alternating glacial and interglacial conditions,much of the sediment in accessible gas hydrate stability zones (GHSZ) may havethe same well bed-differentiated, coarse grained character of excellent NGHreservoir hosts. These reservoirs are of the same type that may hostconventional hydrocarbon deposits in more deeply buried sediments. Existingindustry exploration techniques have been used to identify potential NGHdrilling targets, and drilling in the northern Gulf of Mexico has validated theexploration technique. The Nankai deposits off SE Japan and the depositsdrilled in the northern Gulf of Mexico are excellent examples of thesand-turbidite continental margin paratype. It is estimated from examples andapplication of NGH petroleum system analysis that over 6,000 Tcf of natural gasin place may be present in NGH-enriched deepwater turbidite sands within deepcontinental shelf and slope sediments of the Arctic Ocean. In addition todeepwater turbidites, which are well known from other continental margin areas,such as the Gulf of Mexico, two other prospective zones may exist in the ArcticOcean. Troughs, which are glacially excavated depressions that generally deepentoward the shelf margins, may host NGH in sediments that are transitionalbetween the deepwater turbidites and continental shelf sedimentation.Concentrations of NGH may also be accessible from isolated outliers, which areupstanding continental crust fragments that are present within the Amerasia andEurasia Basins.
Maqbool, Zohaib (Eastern Testing Services (Pvt.) Ltd.) | Khattak, Kifayat (Eastern Testing Services (Pvt.) Ltd.) | Malik, Javaid Hussain (Eastern Testing Services (Pvt.) Ltd.) | Ahmed, Jawad (MOL Pakistan Oil and Gas Company B.V.)
Well testing is an important tool for field appraisal, field development, reservoir surveillance and management. Some key measurements during well tests are flow rates of individual phases, fluid properties, fluid composition, flowing surface, down hole pressure and temperature etc. Analysis of this data helps in pinpointing where improvements can be made, how the productive potential of the reservoir can be enhanced and where the future investments are to be focused. So production testing campaigns of wells are to be conducted and should be conducted annually or bi-annually to get the aforesaid vital information of the well and the reservoir.
While gathering vital data during production testing, an apprehension is that the hydrocarbon produced and separated on surface should not be flared, as it can cause a huge financial loss and environmental harm. Therefore, a zero flaring concept was adopted during production in which the separated gas was safely and effectively injected back to the production line and the fluids to the storage facility.
In Pakistan, production testing is generally carried out using conventional 1440psi separator and implementing zero flaring concepts. But there are certain limitations associated with the conventional 1440 psi separators available in the country. A few of them are that they cannot be used on wells whose downstream pressure or injection line pressure is greater than the safety limit of 1440 psi separator. They cannot be used on wells with high gas rates greater than the maximum limit of conventional 1440 psi separator which is 60 MMSCFD and the same limitation applies to condensate/oil/water rate as well. For this reason there are certain fields in Northern Pakistan where production testing campaigns with zero flaring cannot be carried out due to the above mentioned limitations of 1440 psi separator.
This paper describes the introduction of the first ever High Pressure (HP) separator in Pakistan. This separator has overcome the limitations due to its high design pressure of 2160 psi and high gas and oil flow rate capacity which in 90 MMSCFD and 13000 bpd respectively. Successful field applications at three different fields in Pakistan are discussed in this paper covering lesson learned and best practices during the operations. Producing wells were tested without flaring or wasting any hydrocarbon which is harmful to environment. All the separated gas was injected back to the high pressure production line which resulted in a huge financial advantage. The application of the non-conventional high pressure separator and implementing zero flaring is proven to be a beneficial solution with huge potential for future applications in Pakistan.
CO2/CH4 exchange in a sandstone-hosted methane hydratereservoir was executed in the field, following several years of laboratoryexperimentation. Reservoir simulation and laboratory data informedfieldtrial design, including use of a cell-to-cell model that included correctliquid/vapor/hydrate phase behavior of methane, carbon dioxide, nitrogen, andwater.
Most concepts for producing methane from hydrate deposits rely ondepressurization, heating, or chemical melting. These techniques resultin dissociation of hydrate into its water and gas constituents. Effectiveexchange of CO2 for CH4 in the crystalline hydratelattice, without dissociation, was long deemed an improbable recovery strategybecause experimental results on bulk hydrate samples indicated very slowreaction kinetics. Recent laboratory tests documented enhanced exchangekinetics and efficiency, attributed to the increased surface area present inporous media. A series of laboratory tests ranging from simple gas-richsystems to more complex gas-deficient / water-rich systems guided the design ofa field test program. Ignik Sikumi #1 was drilled in 2011 on the AlaskaNorth Slope, designed specifically for testing CO2/CH4exchange in hydrate-bearing sandstones.
Ignik Sikumi #1 was drilled vertically with chilled oil-based mud to a depthof 2600ft. Four hydrate-bearing sandstones were encountered, andpetrophysical evaluation indicated the Sagavanirktok "C Sand" hosted thehighest hydrate saturations. These sandstones occur in the subsurface atreservoir conditions similar to temperatures and pressure conditions of labtests. Reservoir modeling with conventional simulators and in-housecell-to-cell models guided both equipment design and test parameters. Anticipated low injection rates and cryogenic injectant required the design ofspecialized pumping equipment. Operations at Ignik Sikumi #1 re-commencedin December 2011. Following perforation, over 200,000 scf of mixedCO2/N2 gas was injected. A short unassisted flowperiod was followed by extended production testing via jet pumping. Results from the production test will be shown.
CO2/CH4 exchange is a novel approach to recovermethane from sandstone-hosted hydrates. Field trial has validatedlaboratory results and reservoir simulations, and has proven thatCO2 can be injected into naturally occurring sandstone-hostedhydrates. Subsequent flowback/drawdown testing produced injectants(nitrogen, carbon dioxide, and tracer gases) methane, water, and very finesand.
The development of arctic resources requires wells to be drilled, cased, andcemented through permafrost. Permafrost presents unique challenges, especiallyto cementing operations, requiring a cement system with the capability toperform in the subfreezing permafrost environment. The performance required isthat the cement provides isolation, exhibits low heat of hydration, and setswith sufficient strength to provide casing support. There are also specifictesting requirements detailed in API recommended practices.
In the polar region, there are several approaches used in the design of cementsystems. The approaches used in Russia, Canada, and USA (Alaska) areillustrated. The design considerations take into account local conditions andrequirements and use knowledge from cementing practices employed in thedrilling industry.
It is important to understand the current cementing practices in use withinthe arctic region. This will allow future improvements as more developmenttakes place and the resources become exploited.