This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Africa (Sub-Sahara) United Hydrocarbon International finished drilling the Belanga North-1 exploration well located in Doba basin in southern Chad. The well was drilled to a total depth of 1392 m, and encountered three oil-bearing sand intervals--two in the targeted Upper Cretaceous "YO" sands and one in an untested shallower sand. United Hydrocarbon (100%) is the operator. Asia Pacific China National Offshore Oil Corporation discovered natural gas in the Qiongdongan basin, South China Sea. Well Lingshui 17-2--located in the east Lingshui sag portion of the basin at an average water depth of 1450 m--was drilled and completed to a depth of 3510 m. Lingshui 17-2 encountered a gas reservoir with a total thickness of approximately 55 m. Statoil Australia Theta has drilled and completed the Oz-Alpha 1 exploration well in the southern Georgina basin in the Northern Territory, Australia.
The natural decline in oil production in Alaskan reservoirs is challenging producers to find methods to extend production. The current stage of reservoir development has reached the point where consideration of enhanced oil recovery methods is appropriate. Such methods could include CO2, chemical, microbial or thermal recovery. However, these methods require significant capital and/or operational investment. This paper evaluates the application of wettability alteration for Alaskan reservoirs by changing injection water chemistry also known as advanced water flooding. We use empirically-based screening and scoping methodologies to evaluate the suitability, cost and benefits of advanced water flooding for Alaskan reservoirs using public domain data.
First, laboratory and field examples of successes and failures are considered. Using this basis, a theory is developed that directly links water chemistry and reservoir wettability. The theory also illuminates the key characteristics of the reservoir that control wettability. We use empirically-based screening and scoping methodologies to evaluate the suitability, cost and benefits of advanced water flooding for Alaskan reservoirs with sufficient public domain data. The screening tool is built on empirical data from laboratory and field tests that identify the critical factors contributing to incremental production. The scoping tool uses a modified Kinder Morgan approach (dimensionless recovery curve) to evaluate the economic case for each reservoir.
The first field-scale tests of this technique were conducted by BP in the Endicott reservoir on the North Slope and produced good results by lowering the salinity of injection water. Those tests showed that alteration to injection water chemistry can increase recovery significantly. These results have been duplicated in laboratory and field tests in other locations. The tests were conducted without an understanding of the fundamental mechanisms nor optimization of the injected water chemistry, and thus represent minimum recovery. We find the increased recovery is profitable for several fields depending on assumptions about water sources, water treatment costs and rates of injection.
The successful approach to advanced waterflooding requires several key steps: screening the formation to evaluate the applicability of the technique, simple laboratory tests to determine the optimal water chemistry and quantify the increased recovery, economic evaluations to estimate costs and benefits, and finally, comprehensive geochemical models to design the wettability-modifying fluids. The technique has several advantages compared to current methodologies for wettability alteration including substantially lower costs, no environmental impacts and ease of application.
Using a database from Niger Delta, this study developed correlation of well completion/production efficiency as functions of pressure drawdown and sand control type to quantitatively evaluate the effect of pressure drawdown on well performance.
Generally, Completion/performance efficiency declines exponentially with reservoir pressure drawdown. Critical pressure drawdown for various sand control types beyond which significant formation damage will occur are recommended. Apart from external gravel-pack (EGP) and milled casing under-reamed gravel-pack (MCUGP) wells which can tolerate drawdown of ±400 psi, the critical drawdown for other sand control types is ±250psi. With these correlations, drawdown for tubing conveyed perforation can be carefully designed and well completions evaluated. More so, real time prediction of production performance efficiency can be evaluated given the pressure drawdown.
Situated on the central North Slope of Alaska along the Coleville River, Umiat is one of the most frigid places on Earth. The target reservoir, the Lower Grandstand, lies at an average depth of just 470 ft below ground level and is one of the largest untapped oil fields in Alaska bearing light, sweet crude in a low-energy reservoir. Conventional drilling and completions would cripple the development economics and make too large of an environmental impact at the surface. Developing methods to drill horizontally in permafrost, a task never before achieved in Alaska, would enhance Umiat production compared to that from conventional well geometries. However, the subsurface drilling environment presented challenges since the majority of directional drilling would be in permafrost. With limited infrastructure in place for year-round access to the region, Linc Energy built over 100 miles of snow and ice roads to gain access during Alaska's coldest months. This limits access for drilling from January through the initiation of the cold breakup in late April.
During well planning, the bottomhole assemblies for high dogleg and shallow horizontal landing were optimized by applying experience drilling wells in permafrost in other areas across the North Slope. A new mineral-oil-base reservoir drilling fluid was proposed to provide formation compatibility and low mud weight while reducing friction. Close communication with the rig and office teams was established to enable critical decisions to be taken using drilling dynamics measurements to monitor tripping loads and to geosteer the well.
While drilling the well, the directional drilling response was better than expected landing the horizontal. The risk of stuck pipe was greater than anticipated. As anticipated in the modeling, additional weight was added on the top of the drillstring to avoid pipe buckle and to assist with weight transfer. The new reservoir drilling fluid achieved a density just a half-pound per gallon above the pore pressure and produced sufficient lubricity to reach well depth, thus validating the accuracy of the predrill modelling. The first horizontal well in Umiat was a success, achieving an extended reach drilling ratio of 3.23 with 800 BOPD production rates and 0% water cut. The well set two important records as the shallowest horizontal well drilled in Alaska and the first horizontal well drilled and landed entirely in permafrost in Alaska.
The results of these methods and processes demonstrated that horizontal wells can be drilled in permafrost as this was the first such well in Alaska. The lessons learned on this well will be instrumental for future horizontal wells drilled in permafrost and will enable future permafrost reservoirs to be drilled and produced with horizontal geometry worldwide.
Current high oil price and availability of new technologies allow re-evaluation of oil resources previously considered uneconomic. Umiat oil field is one such resource: a unique, shallow (275-1055 feet), low-pressure (200-400 psia) reservoir within the permafrost zone with no initial gas cap located north of the Arctic Circle, 80 miles west of Trans Alaska Pipeline System (TAPS) with an estimated 1.5 billion barrels of oil-in-place.
A static model was built based on reinterpretation of original log and core data and seismic information. A permeability anisotropy ratio of 0.45 was incorporated into the geologic model. A Monte Carlo simulation was conducted to estimate the different degrees of uncertainty in the original oil in place (OOIP) estimates. To cover the wide permeability range (0-500 md), three sand groups (rock types) were defined and assigned appropriate capillary pressure and relative permeability curves. These were included in the dynamic model along with measured PVT data and gas-oil relative permeabilities in the presence of ice to evaluate the performance of immiscible gas injection using a multilateral wagon wheel well pattern with horizontal well length of 1500 ft.
The simulation results show that with 50 years of gas injection, recovery factors for the base case (400 psia injection pressure) and a case with 600 psia injection pressure are 12% and 15%, respectively, keeping other parameters constant. Those recovery numbers reduce by 18% and 6% when producing GOR is restricted to 5,000 scf/STB and 10,000 scf/STB, respectively. The potential effect of natural fractures was modelled by considering the effect of permeability anisotropy (Kv/Kh).. Simulation results indicate that lower anisotropy ratios will reduce oil recovery, probably due to inhibition of downward gas movement.
The results obtained in this study contribute to the understanding of uncertainties in resource estimation and evaluating ranges of oil recovery in reservoir modeling. Despite limited data and lack of production history to tune the model, the results demonstrate that the proposed development plan bears a high degree of uncertainty and risk. These findings strongly encourage the operator to include in development plan strategies to reduce the risk by enhancing the quantity and quality of simulation input data.
Umiat field is located in the North Slope, Alaska where most oil reserves are within the permafrost. The formation temperature is around 20°F and thus frozen filtrate is a crucial issue in formation damage. Frozen filtrate can form an impermeable barrier to oil flow and maximize formation damage in the permafrost. Its impact is even more pronounced in horizontal wells. In addition to formation damage concerns, low formation pressure, sensitive arctic environment and ice disintegration when exposed to certain fluids are key factors to be considered when selecting the suitable drilling fluid.
This paper is a comprehensive experimental investigation of various drilling fluids to eventually propose a non-damaging fluid system that is suitable for permafrost drilling operations. Specially formulated, free-solid mud systems including WBM, brine mud, native crude OBM, synthetic oil mud, emulsion and foam are evaluated. The evaluation includes their rheological properties, filtration properties, clay swelling properties and potential freezing of fluid filtrate.
The results show that WBM drastically damage the formation. Yet, clay swelling is not a major issue. Freezing of water filtrate is the key damaging mechanism. In spite of its large filtrate volume, brine mud shows a moderate impact on formation damage. Its depressed freezing point makes it suitable for the drilling operations. However, it may not be preferable due to its ice disintegration effects. OBM and synthetic oil mud yield the minimal damage and show excellent rheological and filtration properties. Their depressed freezing point favors their use. Foams and emulsions exhibit numerous advantages. The analysis and evaluation of the different fluid systems is discussed in more details in the present paper. Finally, a specific formulation of drilling fluid is recommended to alleviate the formation damage and production impairment problems and to effectively reduce the well completion cost and eventually, to increase well productivity from such shallow frozen oil field.
Hanks, Catherine (University of Alaska - Fairbanks) | Shimer, Grant (U. of Alaska- Fairbanks) | Ahmadi, Mohabbat (University of Texas At Austin) | Oraki Kohshour, Iman (University of Alaska Fairbanks) | McCarthy, Paul (University of Alaska - Fairbanks) | Dandekar, Abhijit Yeshwant | Mongrain, Joanna | Wentz, Raelene | Davis, Jeremy
The Umiat field in northern Alaska is a shallow, light oil accumulation with an estimated OOIP of ~ 1.52 billion barrels with 99 bcf associated gas. The field was discovered in 1946 but was never considered viable because it is shallow, in the permafrost, and far from any infrastructure. Modern drilling and production techniques make Umiat an attractive exploration and production target. However, little is known about the behavior of a rock/ice/light oil system at low pressures. This information and a robust reservoir model are needed to evaluate the effectiveness of different production methods in this type of accumulation.
Umiat consists of shoreface and deltaic Cretaceous sandstones deformed by a thrust-related anticline. New data indicate the reservoir has six facies associations with distinctive permeability trends. These trends combined with diagenetic effects and natural fractures impart a strong vertical and horizontal permeability anisotropy to the reservoir that needs to be accounted for in reservoir simulation.
Understanding rock and fluid behavior under these conditions is critical for valid simulations. Experimental and theoretical studies indicate that there is a significant reduction in the relative permeability of oil in the presence of ice, with a maximum reduction when connate water is fresh and less reduction when water is saline. The small amount of available Umiat oil was severely weathered and limited traditional PVT and phase behavior analysis. A unique method was developed to physically recreate a pseudo-live reservoir oil sample by comparing the composition of the weathered Umiat fluid with a theoretical Umiat composition derived using the Pedersen method.
These data are being integrated into a simulation model to test production techniques such as cold gas injection. Success at Umiat will pave the way for development of a unique class of Arctic reservoirs.
Hanks, Catherine (UAF) | Shimer, Grant (UAF) | Davis, Jeremy (UAF) | Wentz, Raelene (UAF) | Godabrelidze, Vasil (UAF) | Shukla, Chinmay (UAF) | Levi-Johnson, Obioma (UAF) | Huckaby, Allen (Renaissance Alaska LLC) | McCarthy, Paul (UAF) | Mongrain, Joanna (UAF) | Dandekar, Abhijit (UAF) | Bangia, Vijay (Renaissance Alaska LLC)
Shallow light oil accumulations in reservoirs within the permafrost are rarely recognized and, when identified, are often considered uneconomic because of their shallow depths and low reservoir energy. Horizontal drilling technology will improve the economics of these shallow accumulations, but a better understanding of the reservoir and fluid behavior under these low temperature and pressure conditions will improve recovery and lower development risk. However, little data is available on how a rock/ice/light oil system behaves at low pressures. This information and a robust reservoir model are needed to evaluate the effectiveness of different production methods in this type of accumulation.
The Umiat field of northern Alaska was discovered in the 1940's and is a remote, shallow, light oil accumulation consisting of multiple deltaic and marginal marine Cretaceous sandstones deformed by a thrust-related anticline. While the accumulation may be significant (1.2 billion barrels OOIP), it is shallow and partly in the permafrost zone.
New sedimentologic and structural studies indicate the reservoir has a complex permeability structure that will both impact both the placement of horizontal wells and subsequent reservoir performance. Reservoir sands generally consist of prograding wave-dominated shoreface deposits with good vertical permeability overlain by river-dominated deltaic deposits with poorer vertical permeability. Two different sets of natural fractures may also impart a strong permeability anisotropy to the reservoir.
The temperature profile of the reservoir will also impact reservoir performance and will have to be incorporated into the reservoir simulation. Fluid flow experiments on samples of the Umiat reservoir at sub-freezing temperatures show a reduction in gas and oil relative permeability in the presence of interstitial ice, with the greatest reductions at lower temperatures. A representative Umiat oil sample has been recreated and used to calibrate an Equation of State (EOS) model that can then be used to predict the properties of a representative Umiat fluid in the simulation.
Copyright 2006, Society of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE Western Regional/AAPG Pacific Section/GSA Cordilleran Section Joint Meeting held in Anchorage, Alaska, U.S.A., 8-10 May 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Abstract Alaska's North Slope and the United Kingdom North Sea were petroleum frontiers in the truest sense around 1960 when industry gained access to both areas. Exploration of these two petroleum provinces progressed almost simultaneously with both emerging as significant sources of oil and gas. Both provinces entered the 1960's with no oil production, but, by the end of the 20th century, the provinces combined had delivered almost 50 billion barrels of oil equivalent to markets in Europe and the United States. Alaska's North Slope started producing oil at about the same time as the United Kingdom North Sea, in the mid to late 1970's.