The industry's approach on SAGD injector well completion design is evolving in complexity by increasing the amount of steam-outflow distribution points along the horizontal wellbore. The main drivers in this evolution process are improved steam conformance and uniform chamber growth. Despite this trend, there are not many technical papers covering the criteria for selecting steam outflow locations, quantity and steam flow rate ratio at each distribution point.
This paper describes a case study of a SAGD injector well completion design comprised of two parallel strings and multiple outflow control devices placed along the well's long string. We modeled the steam outflow profile into the reservoir with a commercial thermal wellbore simulator, which is coupled to a series of reservoir cells along the horizontal wellbore.
We based the preliminary completion design on the subsurface parameters that control steam flow into the reservoir (i.e. permeability, thickness, bitumen saturation, etc.). We derived these parameters from an up-to-date geological model based on core data, open-hole logs and cuttings analysis. At the end of the well's circulation phase, we ran a series of temperature falloff logs from planned shut-in periods. We used fiber optic and thermocouple temperature data sets to perform thermal transient analysis, which allowed identifying the location of local/preliminary steam chambers and fingering phenomena. This diagnostic analysis generated a revision on the well's preliminary completion design and steam outflow reservoir parameters.
We carried out a final design using real SAGD performance data obtained from thermal transient analysis. The design objective was to negate the uncharacteristic steam chamber growth features, developed during the circulation phase, to promote uniform development along the wellbore. This paper provides a methodology and criteria for SAGD injector completion design that can be broadly applied across the industry, integrating wellbore hydraulics, reservoir properties and thermal transient analysis into the design process.
Over a period of 4 to 6 months one of the Kristin wells had experienced a rapid decline in production. The drop was unexpected and at the time there was no detectable formation water breakthrough in the well. The decline in productivity was interrupted by a number of erratic, but temporary, surges in production that fell off again soon after. By comparing the well performance with other wells having the same downhole completion type, attention was soon focused on the likelihood of in-situ CaCO3 scale deposition. The subsequent discovery of CaCO3 deposition in the near wellbore area was partly anticipated. However, the discovery of halide scale (by precipitation) and salt (by evaporation) deposition came as a major surprise given that the Kristin formation water contains less than 10% of Total Dissolved Solids (TDS). This paper will describe the early diagnostic approach to screen and finally identify the most likely cause of the productivity loss. It will present the multiple well treatments that followed, the logics, the results and their interpretations. In addition to the results from these multiple treatments the paper will provide a mechanistic explanation of such deposition processes. Most interestingly, a novel observation will be put forward in this paper to underline the erratic and temporary surges of production during the decline period and that can be attributed to a ‘self-healing' mechanism.
Kristin is a gas condensate field located in the Haltenbanken basin about 20km south-west of the Åsgard field. It consists of two main reservoirs, Garn and Ile, and a third but smaller formation, Tofte. Kristin has an initial reservoir pressure of 911bar and a downhole temperature of 170oC. The field has 12 production wells which are linked to the semi submersible production platform (SEMI) via 4 subsea templates (Figure 1). These templates are located between 6 to 7km away and from which the gas is produced via 6X 10" ID flowlines to the SEMI. As a HPHT field Kristin commissioned detailed studies on the risk of scale deposition when the field was first developed. Significant risk of calcite scale was identified whilst halide scale was considered to be a low risk (Asheim 2000) due to the modest salinity in its formation water (Table 1). These studies led to the recommendation and final installation of a purpose built chemical storage and injection unit on the platform and the laying of 2 dedicated service lines (3.5?? ID mild steel) linking them with the various templates, and a comprehensive chemical screening program was initiated (Hustad et al. 2007, Wat et al. 2007).
Kristin drainage strategy is by natural depletion. Since the production started in November 2005 the reservoir pressure has declined and is varying between 400 bar to 700 bar today. Formation water (FW) breakthrough came in April 2007 with the very first dissolver treatment followed shortly (Wat et al. 2008). Today 4 Kristin wells are producing FW and all have experienced CaCO3 related problems to some degree. The impact on production has been minimal however due to the ability to carry out swift remedial treatments, i.e. dissolver and squeeze, using the dedicated injection unit on the SEMI. There were 8 and 9 treatments carried out in 2008 & 2009 respectively and the number is expected to increase as more wells will have FW breakthrough and the water cut will rise.
Wat, Rex Man Shing (Statoil ASA) | Wennberg, Kjell Erik (Statoil) | Holden, Randi (StatoilHydro) | Hustad, Britt Marie (Statoil ASA) | Heath, Steve (Clariant Oil Services) | Archibald, Marc (Clariant Oil Services) | Singdahlsen, Kristian (Clariant Oil Services)
With an initial reservoir pressure of 911bar and a downhole temperature of 170oC Kristin is the first HPHT field in the world that has been completed and produced using subsea solutions. CaCO3 scale has been identified as the major production problem due to the expected high draw down from the reservoir together with the high level of bicarbonate and calcium in the formation water. In April 2007 breakthrough of formation water in two of the wells were detected and the subsurface safety valve in one of them showed increasing inertia. In August/September 2007 the first combined scale dissolver & squeeze treatments were carried out in these two wells. This culminated after more than 5 years of testing of a large variety of chemicals and operational planning. The jobs were successfully carried out using the unique HP injection system on board that is dedicated for such well intervention. In this paper a full case history of these first treatments on Kristin will be presented. It starts with a brief summary of the difficult path to qualify various chemicals for the challenging conditions. This is followed by the early detection, diagnosis and data interpretation processes when the formation water first broke through. The paper will include the operational planning with special focus on the constraints to inject chemicals at an adequate rate against a HPHT
well. The challenges in delivering and maintaining separation of the different chemical pills to a well lying 7km away will be highlighted. Despite the best intension some compromises on the treatment design have to be made in order to maintain safety and system integrity and these will be discussed. Finally the paper will conclude by presenting the results from these treatments, the assessment of the operations, the experiences being learnt and the area identified for future improvement.
Stalker, Robert (Scaled Solutions Limited) | Butler, Kristen (Scaled Solutions Limited) | Graham, Gordon Michael (Scaled Solutions Limited) | Wat, Rex Man Shing (Statoil ASA) | Hauge, Lars-Even (Statoil ASA) | Wennberg, Kjell Erik (Statoil)
Downhole scaling has long been recognized as causing significant damage to the near wellbore area of production wells. Furthermore complex heterogeneous wells, represent a significant challenge to ensuring effective placement and thereby protection along the entire length of the wells, as the injected chemicals (inhibitor or dissolver) naturally enter the higher permeability / lower pressure zones which may leave other zones untreated. Recent publications and field trials have demonstrated the benefits of using modified, lightly viscosified shear-thinning fluids to give more even placement of chemicals in such wells via bullheading. However, when large volumes of polymer gel are used the in situ fluid properties (viscosity) become critical as the fluid penetrates further into the formation. The in situ viscosity affects both the ability to place treatment chemicals into low permeability / high pressure zones and the post-job well clean up. Accurate prediction of the flow behaviour of these gels in porous media depends on the characterization of the physical properties of the reservoir zones, in particular the permeability, effective porosity and most importantly with shear thinning fluids - the formation shape factor. In this paper we present work investigating the suitability of such shear thinning fluids for non-damaging chemical interventions for an HPHT field. The paper will describe thermal stability tests and novel techniques developed to characterize non-Newtonian fluid behaviour under flow conditions between 120oC and 170oC. Results from bulk, coil and core tests will be included. The paper will also describe test protocols developed to investigate the parameters which could influence the formation shape factor. The work clearly demonstrates the significant impact that the shape factor has on diverting fluid into the low injectivity zones. The results will help achieve more even chemical placement and therefore improved scale protection/removal in the wellbore following treatments in complex wells.
Selecting an effective scale inhibitor for squeeze application at 170°C is no simple task. The traditional thermal stability test by aging the chemical in bulk is often perceived to be too harsh. This results in many promising products being rejected due to their apparent degradation at temperature. The alternative of conducting aging test inside core materials, hence more representative to the downhole conditions, is NOT a novel idea. However, no definitive data is available to date that can substantiate such argument and quantify the difference between the two methods. This is mainly due to the difficulties and complexity to conduct such an experiment at high temperature over a long period of time. In this paper, the results from a recent investigation are presented. It describes the detailed procedures during the planning and execution stages, lessons learnt and pitfall to avoid. A scale inhibitor was aged using two different methods, one in bulk as commonly practiced in the industry and one inside a sandstone core. The aging period varied between 45 days as in the bulk and 110 days as for the last desorbed sample from the core. The samples which were aged inside the core retained much of their inhibition efficiency whilst that aged by the traditional method (bulk) lost nearly all its effectiveness. These results CLEARLY demonstrate that the conventional method of thermal aging in bulk is unrepresentative and that the loss in performance can be quantified. A NOVEL finding from this study is the evidences of an unexpected relationship between desorption and inhibition effectiveness. The findings from this study will have great impact on selecting chemicals for HT applications. More so in those environmental sensitive regions where the use of 'yellow' (biodegradable) squeeze chemicals are mandatory. Many of these have been discarded due to their apparent thermal degradation which is now proved to be unrepresentative.
For Newtonian viscous fluid injection into layered linear and radial systems with no crossflow, we concluded: (i) Viscous fluid injection into a layered linear or radial no crossflow system causes diversion of fluid to the low k layer; (ii) This diversion is much larger in a linear system than in a radial system where it is not very significant; (iii) Implications from these points are: (a) results from nocrossflow linear systems (such as parallel core experiments) are actively misleading in terms of radial placement; and (b) we should use modelling to examine placement - using data from 1D core flood experiments to supply parameters (e.g. on effective viscosities etc.) Non-Newtonian Fluids in Porous Media In situ shear rate: The study of the flow of non-Newtonian fluids through porous media has a long history owing to its potential importance in enhanced oil recovery (EOR) processes such as polymer and surfactant flooding
Williams, Helen (Scaled Solutions Limited) | Wat, Rex Man Shing (Statoil ASA) | Chen, Ping (Champion Technologies Ltd.) | Hagen, Thomas (Champion Technologies Ltd.) | Wennberg, Kjell Erik (Statoil) | Vikin, Vigdis (Statoil) | Graham, Gordon M. (Scaled Solutions Limited)
In several high temperature and high pressure (HT/HP) production environments severe downhole carbonate scale formation is often anticipated and effective carbonate scale dissolvers are required. However for most cases the selection of scale dissolvers is conducted under much less severe conditions, involving simple bottle tests conducted at temperatures up to 95ºC and ambient pressure. These tests although generally accepted for screening purposes suffer a number of significant limitations. In addition to the moderate test conditions the low pressure means that carbon dioxide is readily released following the dissolution and results in changes in the test pH which may mean the efficiency of the dissolvers could be overstated.
This paper describes the use of a novel a novel HP/HT "stirred reactor" test rig to more closely examine the relative performance of selected scale dissolvers including organic acids (formic and acetic acids), inorganic acids (16% HCl) and other more conventional scale dissolvers under typical field application conditions. The equipment is specially designed for the extraction and stabilisation of samples at or ‘near' tested conditions and therefore allows the equilibrium dissolution level to be determined under more representative HP/HT conditions. In this work preliminary tests were conducted using 16% HCl under progressively more severe test conditions (RT & 1,500 psi; 150ºC & 1,500 psi and then 150ºC & 4,500 psi. Further tests were then conducted to compare the performance of organic acid based scale dissolvers (formic acid and acetic acid based products) together with other selected scale dissolvers at 150ºC and 4,500 psi and compared with the results obtained for 16% HCl. For these HP/HT tests, samples were collected and analysed after 2 and 20 hours equilibration time and results were compared with those obtained in more conventional "bottle tests conducted at less severe environmental conditions (90ºC and ambient pressure).
In summary the results demonstrate the importance of conducting scale dissolver tests for field applications under more representative (HP/HT) conditions.Of particular significance was the impact of the cooling and pressure reductions.For one of the products tested, although very good dissolution was recorded under the HP/HT conditions, re-precipitation of a different polymorph of calcium carbonate occurred very rapidly resulting in a significant increase in the volume of carbonate precipitation within the reaction vessel and various sample lines. The paper will describe the details of the test equipment used in this work and present a mechanistic interpretation of the various results obtained.