fax 01-972-952-9435. AbstractDuring the drilling and completion of the Huldra field in the North Sea, high temperature and high pressure conditions were expected and encountered in the reservoir section. The difference between the pore pressure and the fracturing pressure is small. Cesium formate had been evaluated as a potential drilling and completion fluid, but technical hurdles could not be completely addressed in time for the first well. As a result of well control problems occurring in the first well, with barite sag in the oil based drilling fluid as a contributing factor, it was necessary to use a drilling fluid with insignificant potential for sag. For the first time worldwide the cesium formate brine was chosen as a drilling fluid. This fluid could be delivered solids free with densities up to 2.2 s.g. The required down hole density in the well was 1.91 s.g. At the same time it was necessary to have as little contribution to the equivalent circulating density (ECD) from the flow as possible.The paper describes how the cesium formate brine was used successfully as a drilling and completion fluid. The effect of the fluid on well control, hole cleaning, rate of penetration (ROP), torque/friction, ECD, formation damage, casing wear and hole stability are covered. The paper also describes actions required to minimize losses of this very expensive fluid.The challenges acquiring adequate formations logs while drilling are also described. Finally, the use of cesium formate brine during the completing of the wells with open hole sand screens is outlined.

Summary Matrix-acidizing models have traditionally underpredicted acid-stimulation benefits because of underprediction of wormhole penetration and the corresponding magnitude of completion-skin factors in vertical wells. For long horizontal wells drilled in carbonate reservoirs, productivity enhancement is a function of acid placement and effective wormhole penetration. However, prediction of wormhole penetration requires more effective analysis than that provided by current industry models. This paper presents results of matrix-acid modeling work for horizontal wells and describes a practical engineering tool for analyzing the progress of matrix-acid stimulation in carbonate reservoirs. The wormhole-growth model is based on the Buijse and Glasbergen empirical correlation. Combining with the mechanistic model of the wormhole propagation based on acid transport and fluid loss from a single wormhole, a modified Buijse-Glasbergen wormhole-growth model is developed that relates the wormhole growth rate to the in-situ injection velocity at the tip of the dominant wormhole. The wormhole constitutive model developed in this study also accounts for core-size dependencies seen in laboratory acid-flood experiments. A semianalytical flow correlation is derived for estimating interstitial velocities at the tip of the dominant wormholes based on a number of 3D FEM simulation analyses, accounting for more realistic flow regimes (radial and spherical flow) typically observed in field application. The scaleup procedure developed in this study extends the wormhole geometry and penetration from laboratory flow tests on small cores to field-sized treatments. The scaleup procedure developed in this work can be applied to cemented and uncemented horizontal wells, including barefoot and perforation-cluster completions typically employed in carbonate reservoirs. Application of this modeling shows that acid wormholing through carbonate formations can provide significant stimulation, resulting in post-stimulation skins as low as–3.5 to–4.0 vs. previously predicted values in the –1.0 to–2.0 range.

Matrix acidizing models have traditionally under-predicted acid stimulation benefits due to under-prediction of wormhole penetration and corresponding completion skin factors in vertical wells. For long horizontal wells drilled in carbonate reservoirs, productivity enhancement is a function of acid placement and effective wormhole penetration. However, prediction of wormhole penetration requires more effective analysis than provided by current industry models. This paper presents results of matrix acid modeling work for horizontal wells and describes a practical engineering tool for analyzing the progress of matrix acid stimulation for cemented and un-cemented horizontal well completions typically employed in carbonate reservoirs. An integrated flow model has been developed to predict the wellbore pressure profile and wormhole distribution by tracking the movement of the acid in the wellbore and the formation. Analysis of injection rates and pressures during acid treatment provides engineers with a way to determine the varying injectivity and tubing friction as stimulation proceeds. The model presented here can be used as a forward model for analyzing real-time treatment rate and pressure histories and can also be used to review past treatments to improve future treatment designs. The wormhole growth model is based on Buijse and Glasbergen’s empirical correlation augmented by the effect of formation heterogeneity and scale-up procedures that extend the wormhole geometry and penetration from laboratory flow tests on small cores to field-size treatments. Application of this modeling shows acid wormholing through carbonate formations can provide significant stimulation resulting in post-stimulation skins as low as −3.5 to −4.0 vs. previously predicted values in the −1.0 to −2.0 range. Using actual field stimulation data, we also discuss key elements to successful stimulation planning and the diagnosis of matrix acid treatments to achieve effective wormhole coverage for horizontal completions in carbonate formations.

Summary Successful acid stimulation of long-horizontal-well intervals in carbonate reservoirs requires effective acid distribution along the entire reservoir length. Such treatments also require large volumes of acid and seawater/brine injection at sufficiently high injection rates to drive the acid wormholes deep into the reservoir. Under these flowing conditions, significantly large tubing friction loss is anticipated unless optimal friction reducer performance in the tubing is maintained throughout the pumping operation. Because prediction of wormhole penetration and corresponding skin factor depends on analysis of downhole-injection pressures at the reservoir face, it is crucial to properly account for these hydrostatic and friction changes prior to evaluation of wormhole length and skin factor. In this study, an integrated flow model has been developed to predict the wellbore-pressure profile and wormhole distribution by tracking the movement of the acid in the wellbore and the formation. The wellbore-flow model is based on steady-state, 1D, pressure-based nodal method. The segmented wellbore in the reservoir interval is then coupled with analytical transient reservoir-flow models. The wormhole propagation in the formation is calculated based on the modified Buijse-Glasbergen correlation and upscaling model developed in our earlier work. The resultant wormholing skin factor is calculated by simulating and updating the changing well injectivity along the entire injection interval at every timestep. The model developed in this work is applicable for both fully completed wells (i.e., radial flow) and selectively completed perforation-cluster wells (i.e., spherical flow) typically employed in carbonate reservoirs. Analysis of injection rates and pressures during acid treatment provides engineers with a way to determine the varying injectivity and tubing friction as stimulation proceeds. The model presented here can be used as a forward model for analyzing real-time treatment rate and pressure histories and can also be used to review past treatments to improve future treatment designs. Using actual field-stimulation data, we also discuss key elements to successful stimulation planning and the diagnosis of matrix-acid treatments to achieve effective wormhole coverage for horizontal completions in carbonate formations.

This paper describes the design, testing, installation, and performance of the first 'fully-completed' well using an intelligent inner completion inside an un-cemented liner with openhole packers for zonal isolation. The well design concept evolved from technical challenges associated with completing long cased and cemented laterals in the mature Ekofisk waterflood. The term 'fully-completed' implies full reservoir access along the pay length for production and high rate matrix acid stimulation using limited entry for fluid diversion within well segments.The paper covers the development and qualification of custom openhole 7⅝ in. liner components that can handle high differential pressures and extreme temperature fluctuations, the marriage of this complex liner with a five zone intelligent completion system, and results from a year of system integration testing. The paper also discusses the strategic placement of both mechanical openhole and inner string packers based on caliper and drilling logs; challenges met and overcome during installation; and a remarkable collection of down-hole gauge data that confirms the performance of each component before, during, and after the stimulation.The Ekofisk field waterflood began in 1987 and continues to date, exceeding expectations for improved oil recovery while mitigating reservoir compaction. As the waterflood matures, new wells are more often found partially water-swept. Limited infrastructure for lifting and handling the high water production has led to increased emphasis on isolating these water-swept intervals. Cased, cemented and perforated completions have traditionally been used for this service. It has become increasingly difficult to execute a successful cement job in longer horizontals with 4,000 ft to 8,000 ft laterals where rotation of the liner is impossible and high effective circulating densities (ECDs) limit rates during cementing. Wide variations in reservoir pore pressures, often in excess of 2,000 psi difference along the lateral, are typical of the Ekofisk chalk and exacerbate the difficulties of cementing. As a result, a new method for zonal isolation has been developed to ensure the success of future infill drilling campaigns.The design and careful planning that went into the fully-completed openhole un-cemented liner strategy resulted in a successful field trial and has proven this solution to be an effective alternative to cemented reservoir liners in long horizontals where zonal isolation is critical. Use of the intelligent well system (IWS) allowed offline acid stimulation without rig, coiledtubing, or wireline intervention. What would have traditionally been a significant water producer, with three water-swept zones totaling nearly 2,000 ft across a 4,000 ft reservoir section, has turned out to be one of the best oil producers in the field with nearly zero water cut. Production results show high productivity with highly negative acidized completion skins.With large investments in intelligent completions to provide zone-specific inflow control ...