Weijermans, Peter-Jan (Neptune Energy Netherlands B.V.) | Huibregtse, Paul (Tellures Consult) | Arts, Rob (Neptune Energy Netherlands B.V.) | Benedictus, Tjirk (Neptune Energy Netherlands B.V.) | De Jong, Mat (Neptune Energy Netherlands B.V.) | Hazebelt, Wouter (Neptune Energy Netherlands B.V.) | Vernain-Perriot, Veronique (Neptune Energy Netherlands B.V.) | Van der Most, Michiel (Neptune Energy Netherlands B.V.)
The E17a-A gas field, located offshore The Netherlands in the Southern North Sea, started production in 2009 from Upper Carboniferous sandstones, initially from three wells. Since early production history of the field, the p/z plot extrapolation has consistently shown an apparent Gas Initially In Place (GIIP) which was more than 50% higher than the volumetric GIIP mapped. The origin of the pressure support (e.g. aquifer support, much higher GIIP than mapped) and overall behavior of the field were poorly understood.
An integrated modeling study was carried out to better understand the dynamics of this complex field, evaluate infill potential and optimize recovery. An initial history matching attempt with a simulation model based on a legacy static model highlighted the limitations of existing interpretations in terms of in-place volumes and connectivity. The structural interpretation of the field was revisited and a novel facies modeling methodology was developed. 3D training images, constructed from reservoir analogue and outcrop data integrated with deterministic reservoir body mapping, allowed successful application of Multi Point Statistics techniques to generate plausible reservoir body geometry, dimensions and connectivity.
Following a series of static-dynamic iterations, a satisfying history match was achieved which matches observed reservoir pressure data, flowing wellhead pressure data, water influx trends in the wells and RFT pressure profiles of two more recent production wells. The new facies modeling methodology, using outcrop analogue data as deterministic input, and a revised seismic interpretation were key improvements to the static model. Apart from resolving the magnitude of GIIP and aquifer pressure support, the reservoir characterization and simulation study provided valuable insights into the overall dynamics of the field – e.g. crossflows between compartments, water encroachment patterns and vertical communication. Based on the model a promising infill target was identified at an up-dip location in the west of the field which looked favorable in terms of increasing production and optimizing recovery. At the time of writing, the new well has just been drilled. Preliminary logging results of the well will be briefly discussed and compared to pre-drill predictions based on the results of the integrated reservoir characterization and simulation study.
The new facies modeling methodology presented is in principle applicable to a number of Carboniferous gas fields in the Southern North Sea. Application of this method can lead to improved understanding and optimized recovery. In addition, this case study demonstrates how truly integrated reservoir characterization and simulation can lead to a revision of an existing view of a field, improve understanding and unlock hidden potential.
S. Ameen and A. Dahi Taleghani, Louisiana State University Summary Injectivity loss is a common problem in unconsolidated-sand formations. Injection of water into a poorly cemented granular medium may lead to internal erosion, and consequently formation of preferential flow paths within the medium because of channelization. Channelization in the porous medium might occur when fluid-induced stresses become locally larger than a critical threshold and small grains are dislodged and carried away; hence, porosity and permeability of the medium will evolve along the induced flow paths. Vice versa, flowback during shut-in might carry particles back to the well and cause sand accumulation inside the well, and subsequently loss of injectivity. In most cases, to maintain the injection rate, operators will increase injection pressure and pumping power. The increased injection pressure results in stress changes and possibly further changes in channel patterns around the wellbore. Experimental laboratory studies have confirmed the presence of the transition from uniform Darcy flow to a fingered-pattern flow. To predict these phenomena, a model is needed to fill this gap by predicting the formation of preferential flow paths and their evolution. A model based on the multiphasevolume-fraction concept is used to decompose porosity into mobile and immobile porosities where phases may change spatially, evolve over time, and lead to development of erosional channels depending on injection rates, viscosity, and rock properties. This model will account for both particle release and suspension deposition. By use of this model, a methodology is proposed to derive model parameters from routine injection tests by inverse analysis. The proposed model presents the characteristic behavior of unconsolidated formation during fluid injection and the possible effect of injection parameters on downhole-permeability evolution. Introduction Water injection has been widely used to maximize hydrocarbon sweeping in waterflooding treatments and also to maintain reservoir pressure (Willhite 1986).
The Perdido development is one of the most-complex deepwater projects in the world. It is operated by Shell in partnership with Chevron and BP. It currently produces hydrocarbons from 12 subsea wells penetrating four separate reservoirs. The properties of produced fluid vary per reservoir as well as spatially. The producing wells display a relatively wide range of fluid gravities, between 17 and 41 API, and producing gas/oil ratios (GORs), between 480 and 3,000 scf/bbl. The fluids produced from the subsea wells are blended in the subsea system and lifted to the topside facilities by means of five seabed caisson electrical submersible pumps. In the topside facility, gas and oil are separated, treated, and exported by means of dedicated subsea pipelines. The fluid compositions and properties across the various elements of the production system are used as input data to the respective simulation models, and the corresponding outcomes (e.g., fluid properties, compositions) vary upon the well/caisson lineup and daily operating conditions. Given the wide spectrum of fluids produced through the Perdido spar, a special equation-of-state (EOS) characterization of the fluids had to be developed. Because a common EOS model was used to characterize the fluids, we will call this the unified fluid model (UFM) throughout this study. This approach enables accurate and efficient prediction of the properties of blended fluids and is suitable for use in an integrated-production system model (IPSM) that connects reservoirs, wells, subsea-flowline networks, and topside-facilities models. Such a modeling scheme enables effective integration among relevant engineering disciplines and can represent production and fluid data from field history with high confidence. The IPSM uses a black-oil fluid description for the well and subsea-flowline network models. By use of the initial composition and producing GOR of each well, the fluid composition is estimated by means of a simple delumping scheme. The resulting composition is tracked through the subsea network to the topsidefacilities model, where compositional flash calculations are performed. The IPSM can forecast production rates together with fluid properties and actual oil- and gas-volumetric rates across the whole production system. The model can be used to optimize production under constrained conditions, such as limited gas-compression capacity or plateau oil production.
So far, oil and gas production in the deepwater Gulf of Mexico is mostly from Neogene (Pleistocene, Pliocene, and Upper Miocene) reservoirs. The Neogene reservoirs can be characterized broadly as overpressured, unconsolidated, and highly compacting, with high permeability and containing black undersaturated oil of medium gravity with moderate gas/oil ratio and some aquifer support. Although waterflooding is a mature technology, few water-injection projects have been conducted in the Neogene reservoirs because they exhibit good primary recoveries, exist in high-cost offshore environments, and are relatively small. In some of these fields, a limited volume of water was injected.
This paper details the case history of the highly challenging extended-reach deepwater A-10 well, drilled in the Ursa ("Bear" in Latin) prospect in the Gulf of Mexico (GOM). This 30,000-ft well, drilled from the Ursa tension-leg platform (TLP) at a vertical depth of 18,000 ft and a horizontal displacement (HD) of 20,000 ft, targeted the Yellow sand in the Ursa-Princess section of the greater Mars-Ursa basin. During the drilling of the original hole (OH), two subsequent sidetracks, and two mechanical bypasses, a number of significant hole problems materialized that caused extensive nonproductive time (NPT) and an associated cost overrun. These problems were clearly associated with the drilling of a complex well that combined a high-deviation and extended-reach wellbore with a very narrow and pressure-depleted drilling window, characteristic of the GOM's challenging geopressured environment. In all, at least five independent borehole-failure mechanisms were encountered while drilling the OH and its successive sidetracks/ bypasses, which were exacerbated by an additional complicating factor:
An extensive lookback study was carried out on the Ursa A-10 well, leading to the development of several important lessons learned and best practices [e.g., for hole cleaning, equivalent-circulating- density (ECD) management, sag control], and to the development of new systems (including novel, sag-resistant synthetic- based-mud formulations). A succinct overview of the Ursa A-10 case history and a comprehensive summary of its learnings are provided here to help the future drilling of extended-reach wells in geopressured, low-margin deepwater environments.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24111, "Water Injection in Deepwater, Overpressured Turbidites in the Gulf of Mexico: Past, Present, and Future," by X. Li and K.K. Beadall, SPE, Knowledge Reservoir; S. Duan, SPE, Chevron Corporation; and J.R. Lach, SPE, Knowledge Reservoir, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.
Good primary recovery, high drilling cost, and facility limitations mean water injection is not commonly used in the deepwater Gulf of Mexico. However, waterflooding can supply additional reservoir energy for producing substantial quantities of oil trapped by limited displacement drive and poor sweep efficiency. This paper is a detailed examination of Pleistocene-to-Upper- Miocene turbidite reservoirs in the deepwater Gulf of Mexico under water injection. Waterflooding strategies have proved to be highly effective in achieving good incremental oil recovery from these reservoirs.
So far, oil and gas production in the deepwater Gulf of Mexico is mostly from Neogene (Pleistocene, Pliocene, and Upper Miocene) reservoirs. The Neogene reservoirs can be characterized broadly as overpressured, unconsolidated, and highly compacting, with high permeability and containing black undersaturated oil of medium gravity with moderate gas/ oil ratio and some aquifer support. Although waterflooding is a mature technology, few water-injection projects have been conducted in the Neogene reservoirs because they exhibit good primary recoveries, exist in high-cost offshore environments, and are relatively small. In some of these fields, a limited volume of water was injected.
The Ursa and Princess oil fields lie in the Mississippi Canyon (block 810) of the Gulf of Mexico about 130 miles south east of New Orleans. Both fields produce to a common host, the Ursa Tension Leg Platform, moored in approximately 3,800 ft of water. Ursa production wells were completed with dry tree direct vertical access (DVA) while Princess utilizes wet tree subsea wells tied back about four miles to the host through dual insulated flowlines and risers, as shown in Figure 1. Production at Ursa began in 1999 and Princess in 2004 with both fields producing from the main Lower Yellow (LY) and secondary Sub Yellow (SY) reservoirs. Currently, seven wells are producing from the LY and two from the SY. A waterflood of the LY, comprising four subsea injectors (two in Ursa and two in Princess), was initiated in 2008 in order to replace voidage and improve sweep efficiency and hydrocarbon recovery.
Recent successful production wells in Princess coupled with the waterflood response have created a bottleneck at the subsea flowlines. At current operating conditions, this restriction means that future projects would be have to be deferred as they cannot fully deliver gains due to the back out of existing production. In addition, an earlier screening study had identified Princess as a strong candidate for subsea boosting in order to increase production from existing wells. The asset team therefore initiated a de-bottlenecking and subsea boosting assessment that was carried out by a multidisciplinary team.
A subsurface team formed a part of the greater multidisciplinary team. One of the tasks of the subsurface team was to deliver production functions for each of the screened re-development concepts. Production was one of the key inputs in evaluating economics which in turn was a primary driver of the concept selection decision. While the re-development concepts were specifically for the Princess field, the expectation was that changes there would influence hydrocarbon recovery from Ursa as the two fields are in pressure communication within the main LY reservoir and both benefit from waterflood support. This study also needed to include future Princess subsea wells targeting additional accumulations not in communication with the LY or SY as part of the re-development. These reservoirs are expected to have a range of different initial pressures and contain hydrocarbons of varying properties.
Hence, it became clear at the start that there were several dependent and independent moving components and constraints that had to be considered together to get an accurate assessment of the systemic effects that would influence total production. The team therefore decided to build an integrated production model, containing the entire production system from reservoirs to topsides, to obtain production functions for the screened concepts.
Waterflooding can supply additional reservoir energy for producing substantial quantities of oil trapped due to limited displacement drive and poor sweep efficiency. However, water injection is not commonly used in the deepwater Gulf of Mexico (DW GoM) due to good primary recovery, drilling cost and facility limitations. In over 80 fields and 450 reservoirs, water injection program has been implemented in only 18 reservoirs in 13 fields, or less than 5% of potential waterflooding candidates.
DW GoM mid-Miocene reservoirs are characterized by sparse well counts, over-pressured, and generally good rock and fluid properties. Rock compaction and moderate aquifer influx often provide moderate to good natural drive energy and oil recovery. Primary oil recovery averages 32% with the 80% confidence range between 16% and 48%. However, Paleogene reservoirs are characterized by deeper depth, high pressure, high temperature, complex geology, and rock and fluid properties. Estimated recoverable oil is only 10% of OOIP assuming primary production and limited natural drive energy. Water injection programs will be difficult to execute in tight, abnormally-pressured Paleogene reservoirs. Waterflooding of deepwater turbidites has accumulated many lessons and learns now, and a comprehensive understanding of the influence of depositional environment and injection into over-pressured, highly compacting rocks is necessary. This paper is a detailed examination of Pleistocene-to-Upper Miocene age turbidite reservoirs in the DW GoM under water injection. Issues on waterflooding these deepwater plays were reviewed in the context of geological setting and depositional environment. Despite many drawbacks that tend to oppose the implementation of a waterflooding in Paleogene reservoirs, this paper still proves that they are candidates for water injection programs under the rules of good production practice. Moderate oil recovery is suggested in highly compacting reservoirs with supplemental injection drive. Overall, waterflooding strategies have proven to be highly effective in achieving good incremental oil recovery from the deepwater Gulf of Mexico reservoirs.
In the aftermath of the tragic 2010 Macondo/Deepwater Horizon event, it is important that the industry share case studies on successful wells. It also is important to share information on wells that proved to be very challenging. Sharing learnings, best practices, and experiences on such wells will raise the overall level of proficiency in constructing these wells throughout the industry. As is often the case, more is learned from adversity than from outright success. This is the main reason that the Ursa A-10 case is presented. Over the last decade, world-class extended-reach-drilling (ERD) wells have been drilled in the continued development of the Mars-Ursa basin in the GOM. These This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163525, "Setting Free the Bear: The Challenges and Lessons of the Ursa A-10 Deepwater ERD Well," by John Gradishar, SPE, and Gustavo Ugueto, SPE, Shell Upstream Americas, and Eric van Oort, University of Texas at Austin (formerly with Shell Upstream Americas), prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition held in The Woodlands, Texas, USA, 27-28 March 2012. 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 have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract This paper will present planning and execution details for different mechanical plug types used to prevent fluid loss and formation damage during workover interventions on deepwater wells with extreme hydrostatic overbalance conditions, between 2,000-2,200 psi. Actual case history for four wells, using different mechanical formation plug methods, from one deepwater field in the Gulf of Mexico will be included. The information is applicable to oil producing wells, to be worked over with similar extreme hydrostatic overbalance to producing formations, where well control needs to be maintained during the intervention, fluid loss to the producing formation needs to be minimized and subsequent removal of the isolation barrier is required to restore well production.