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Lookback on Performance of 50 Horizontal Wells Targeting Thin Oil Columns, Mahakam Delta, East Kalimantan
Abstract
This paper presents a case study to look back on the performance of over 50 horizontal wells recently drilled in three different fields in the Mahakam Delta, offshore East Kalimantan, Indonesia. The common application of these horizontal wells is to produce thin oil bands sandwiched between gas cap and bottom/edge aquifer. The objective of the study is to provide lessons learned from the actual well performance data for improving future well planning as horizontal wells continue to be used in these fields.
Based on well performance data, the lookback is mainly focused on the reservoir evaluation aspect of these horizontal wells. Reservoir and well performance is analyzed using a variety of techniques, varying from single-well analytical modeling (or decline curves) to more complex reservoir simulation. Based on statistical data resulted from the analysis of these wells, specific relations between reserves and reservoir-well parameters are identified which will be useful for predicting future well performance, especially during early prognosis. Practical issues related to well planning such as selection of well location, well length, well path, and standoffs to fluid contacts are presented. The paper also discusses specific operational strategy used in drilling, completing, and producing these horizontal wells.
Results from the lookback provide guidelines and refinements for our continuing implementation of horizontal wells to optimize thin-oil-column development in these fields.
... Horizontal and multilateral wells, as opposed to the conventional vertical wells, have proven to reduce coning problems and improve recovery in thin oil rims. Production increases of 2-5 times that of vertical wells have been observed, and horizontal wells are now accepted as the better way to improve recovery (Joshi and Ding, 1996; Vo et al., 2000). This improved performance is attributed to (i) smaller drawdowns which reduce coning effects, (ii) enlarged contact and drainage areas, and (iii) improved sweep, production rates and recovery efficiencies. ...
... One of the key elements for accurate placement of horizontal wells within a thin oil rim, is the building of a detailed geological model. In addition to providing information on the areal extent of the reservoir, sand thicknesses and hydrocarbon volumes, the geological model impacts the well's location, landing point, well length and course, and completion methods, particularly if the well trajectory is to intersect several layers (Vo et al., 2000). Unfortunately, unexpected and abrupt geological uncertainties such as faults and shale-outs can occur and create challenges while drilling. ...
... In order to properly place a horizontal well, the depths to the GOC and the WOC must be known. Operators generally employ one of three techniques to land wells at the correct depth (Vo et al., 2000). The first option, and the most costly, involves drilling a vertical pilot hole to locate the GOC and the WOC. ...
Many hydrocarbon reservoirs have water underlying an oil or gas bearing zone. When placed on production, if a wellbore draws oil or gas from an area near the water zone, the water can be drawn into the wellbore due to the phenomenon of coning. This creates problems because it results in excessive water production compared to the oil or gas production. If the water contains salts such as sodium chloride, these can corrode production facilities, and the produced fluids must be separated before transporting to the refinery. Reduced oil or gas production and increased operating expenses all lead to reduced revenue. Unfortunately, such a situation cannot be avoided if there is a thin oil-bearing layer, sandwiched between a gas cap and bottom or edge water, and in which case gas coning can also occur. Thin oil rims are found in many oil provinces around the world and are especially prominent in the prolific gas province offshore the east coast of Trinidad and Tobago. While oil, the more valuable resource is recovered before extraction of overlying gas, exploitation of these reservoirs poses a challenge for reservoir development, as early gas and water coning severely hinder maximum oil recovery. Alleviating these challenges by reservoir management involves knowing where the fluid contacts are, and optimisation of well placement and fluid withdrawal rates. This paper investigates the problems of thin oil rim reservoirs. It discusses the successful current reservoir management practices for coning carried out in Trinidad within the economic restraints of the liquefied natural gas (LNG) contracts, and demonstrates how multidisciplinary teams, using horizontal wells and good use of modern technology, have successfully exploited the fields off the east coast of Trinidad.
... The program modified the IMEX input dataset corresponding to the predetermined parameters. These parameters Table 3 were selected due to their influence on the recovery process with the typical values for oil rim reservoir Aladeitan et al., 2019;John et al., 2019;Nicot and Duncan, 2012;Olamigoke and Peacock, 2009;Vo et al., 2000;Wagenhofer and Hatzignatiou, 1996 . In general, they represent the ef fect of reser voir structure e.g., reservoir dip , fluid flow dynamics e.g., oil viscosity , and energy drive e.g., the volume ratio of water ...
It is challenging to develop thin oil rim reservoirs economically using conventional wells. Horizontal wells are now widely used to overcome the shortcomings of vertical wells. The deciding factor in ensuring successful horizontal wells application is optimum well placement. However, the conventional optimization approach is time and resource-intensive. A data-driven approach was proposed to optimize heel and toe locations by deploying a deep learning model. A synthetic database comprised of nine fundamental parameters that in uence recovery mechanisms in thin oil reservoirs was generated to train the model. The accuracy and computation time of a deep-learning model trained on a synthetic database were compared to a novel optimization method that combines a genetic algorithm and a particle swarm optimization （hybrid GA-PSO） algorithm. The deep-learning model predicted optimum well placement （heel and toe points） with an accuracy comparable to the hybrid GA-PSO algorithm. Furthermore, the prediction obtained by the deep learning model takes significantly less computation time than the hybrid GA-PSO algorithm. The developed optimization method offers a rapid and reliable initial guess of well placement for detailed optimization by simulation. The developed
model is universally applicable for various thin oil rim characteristics, especially in the scarcity of data to build a reliable reservoir model.
... The interplay of subsurface factors and production constraints determine the dynamics of oil rim reservoir production. Oil recovery from a thin oil column under the influence of gas cap and water influx is strongly dependent on oil column thickness, formation permeability, gas cap size, aquifer strength, reservoir geometry, magnitude of bed dip, and oil viscosity (Vo et al, 2000). ...
... The interplay of subsurface factors and production constraints determine the dynamics of oil rim reservoir production. Oil recovery from a thin oil column under the influence of gas cap and water influx is strongly dependent on oil column thickness, formation permeability, gas cap size, aquifer strength, reservoir geometry, magnitude of bed dip, and oil viscosity (Vo et al, 2000). ...
Most reservoir in mature oil fields are vulnerable to challenges of water and/or gas coning as the size of their oil column reduces due to extensive period of oil production. These often result to low oil production and excessive water and/or gas production. This study therefore seeks to evaluate the occurrence of coning through the movement of fluid contacts in mature oil field reservoir. MBAL petroleum software was used to study the tendency of coning in mature oil field in the Niger delta. Using reservoir production history; fluid saturation, initial pressure, initial fluid contacts and depth data, a simulation was run to predict the future movement of oil-water contact and gas-oil contact with declining pressure. Using the interception on a plot of oil-water contact and gas-oil contact against time, a point where both water and gas are likely to cone was identified. Sensitivity study was also carried out to evaluate the trend of the critical rate with the reduction in oil-column due to the shrinking fluid contact. It was observed that the critical rate reduces with declining oil rim fluid contacts. Therefore to avoid coning in mature oilfield rim, the critical rate of the respective decline in oil column thickness is determined to maximize oil production.
The objective of this paper is to present the comparative results of comprehensive analysis of horizontal well productivity and completion performance with vertical wells drilled and completed within same time window in the Mauddud reservoir in the Bahrain Oil Field. The study also focuses on performance evaluation of horizontal wells drilled in different areas of the field. Key reservoir risks and uncertainties associated with horizontal wells are identified, and contingency and mitigation plans are devised to address them. Besides controlling gas production, the benefits of using cemented horizontal wells over vertical wells are highlighted based on performance of recently completed workovers and economic evaluation.
Reservoir and well performance are analyzed using a variety of analytical techniques such as well productivity index (PI), productivity improvement factor (PIF), normalized productivity improvement factor (PIFn), well productivity coefficient (Cwp), in conjunction with a statistical distribution function to reflect the average and most likely values. In addition, average oil/gas/water production, cumulative production, reserves, and estimated ultimate recovery (EUR) are compared for both vertical and horizontal wells using decline curve analysis. Furthermore, economics are evaluated for tight spacing drilling with vertical wells, as well as horizontal cemented wells, to optimize future development of Mauddud reservoir.
Based on the evaluation, it is inferred that the average horizontal well outperforms a vertical well in terms of production rate, PI, PIF, reserves, and EUR in the field except in waterflood areas. Based on average cumulative oil, reserves and EUR, and well productivity coefficient, overall performance of horizontal wells are better in the GI area in comparison their counterparts in the North/South areas of the Mauddud reservoir, where the dominant mechanism is strong water drive. High gas and water production in horizontal wells are attributed to open-hole completions of the wells and the possibility of poor cementing. A trial has been completed recently in a few horizontal wells using cased-hole cemented completion with selected perforations, resulting in improved oil rates and the drastic reduction of gas to oil ratio. Furthermore, two new cased-hole cemented horizontal wells are planned in 2021 as a trial. A detailed cost-benefit analysis using a net present value concept is performed, leading to a rethink of future development strategies with a mix of both vertical as well as horizontal wells in the GI area.
Using the dimensionless correlations and distribution functions, the productivity and PIF of new horizontal wells to be drilled in any area can be predicted during early prognosis given the values of average reservoir permeability, well length, and fluid properties. This study can be used as a benchmark for the development of a thin oil column with a large and expanding gas cap under crestal gas injection using both vertical and horizontal wells.
The present work is dedicated to the problem of developing oil and gas condensate pools with thin oil rims for neocomian deposits in the Urengoy region, and to the search for effective methods of oil production from thin rims. The key problems in the development of thin rims are the low cumulative oil production per well, as a result - low profitability and oil recovery ratio. The reasons are known: a sharp decline in initial oil rate due to the rapid increase in water cut and growth of gas factor associated with the water and gas coning.
The results of hydrodynamic modeling at early stage in the development of oil rims often lead to optimistic forecasts that are not confirmed in practice. The paper provides an analysis of the reasons for optimistic calculations, tuning up models for the results of the development and operation of oil wells with different completion relative to the GOC. Obtaining history-matched oil and gas production systems made it possible to obtain a more reliable production forecast for oil wells, to substantiate the preferred target subsea depth for the completed interval in the rim and the type of completion.
Scenarios with the completion of the horizontal section at a distance of one third from the GOC and OWC, or in the middle between the contacts, have been considered and analyzed. A comparison of the calculated performance of the wells with the actual one had been made. An economic evaluation of the operational efficiency of wells drilled on thin rims shows that their profitability based on oil production is marginal. The closer completion intervals of the oil horizontal wells to the GOC the higher economic efficiency of their operation due to additional volumes of gas and condensate production from the gas cap. The use of double-wellbore and multi-lateral completion of horizontal wells in the oil rim increases the economic attractiveness of the project.
The integrated approach proposed in the paper to the organization of production and oil and gas processing systems from such oil wells makes it possible to technologically efficiently operate wells and ensure almost full utilization of associated gas. The joint development of gas condensate pools with thin oil rims allows for the cost-effective development of the ones.
Many gas reservoirs critical to providing a reliable supply of gas to the Nigeria Gas market have observed or potential oil rims where only a gas-down-to (GDT) has been logged. Development of these oil rims must be considered as part of the overall hydrocarbon maturation plans for the reservoir. Maturation studies of this type can take a long time and may lead to restrictions on the availability (quantity and timing) of the gas volumes to the market. This poses a serious challenge to maintaining gas supply and meeting contractual obligations.
Field performance of selected oil rim reservoirs in the Niger Delta have been analysed and presented in this work. The main factors that influence oil rim performance are highlighted and oil recovery trends have been established.
In addition, a generic simulation model has also been developed to analyse oil rim dynamics and assess the impact on oil and gas recovery for a range of sub-surface uncertainties. A range of alternate development strategies has been considered. Experimental design was used to obtain oil recovery correlations for each development strategy which has proven to be a useful first pass screening tool to make assessments of the likely oil recovery range from a specific oil rim reservoir. The oil recovery trends obtained from the simulation study have been found to be consistent with actual oil rim performance.
The result of this work is therefore useful for quick screening of oil rims for technical and economic feasibility to support key business decisions before embarking on costly detailed studies, if eventually required, subject to the complexity of the situation and decision required.
Maximizing oil recovery in thin and ultrathin (<30 ft) oil columns is a challenge because of coning or cresting of unwanted fluids, regardless of well orientation. Significant oil is left behind above the well completion even for horizontal wells when bottom- or edge-water invasion occurs.
Two depletion strategies may be enacted to improve recovery of the remaining oil. In the first option, a conventional horizontal is completed below the gas/oil contact (GOC). Once the well waters out, the well is recompleted in the gas zone. Completion occurs either at the crest for a small gas-cap reservoir or at the GOC, inducing reverse cone, for reservoirs with thick-gas columns. Alternatively, one can skip the initial oil completion, where gas disposition is a nonissue. Gravity-stable flooding is required to maximize reserves.
Extensive flow simulations in multiple, history-matched models have shown that the proposed strategy improves recovery significantly. Two field examples are presented to demonstrate the usefulness of the proposed method.
Using multivariate regression, simple correlations were developed for quick screening of the proposed approach. Experimental design formed the backbone of a parametric study involving various reservoir, fluid, and process variables. We tested and validated the correlations with independent sets of experimental and published field data.
Effective exploitation of the thin oil rim in the Amherstia / Immortelle 22 sand is particularly challenging because of the size of the overlaying gas cap, 2TCF, and the thickness of the oil rim varying between 31 to 46 feet gross pay interval. Since oil wells in the thin oil rim of the 22 sand did not justify well cost, the challenge, then, was to make the oil wells more attractive to facilitate early depletion of the oil rim.
Reservoir simulation work was undertaken and a joint team was formed to evaluate the reservoir performance and determine the best strategy for depletion. This team consisted of subsurface professionals from the Amherstia and Immortelle fields, and the bp Houston technology group. The performance of the two wells in the reservoir was history-matched and then the model was used to develop an improved strategy.
The reservoir simulation grid used was aligned with the major fault patterns and nested local grid refinement was utilized to better understand depletion of the oil rim. Sensitivity analysis conducted demonstrated that locating longer horizontal oil wells with larger size tubing in the upper third of the oil rim proved to be the best strategy for depletion of the oil rim. The strategy provided higher production rates with earlier accessibility to gas reserves while outrunning the aquifer.
This paper presents a case study of analysis that leads to the decision to drill the first horizontal oil well (G-21) in the Platong field in the Gulf of Thailand. The application of horizontal well technology in this field is a challenge because of low seismic resolution, small-sized reservoirs, and stacked reservoir systems. Successful use of horizontal well technology requires an integrated team approach that incorporates all available data to justify a business case for drilling the well.
The 37B sand in the Platong field has a 30-foot oil column, a small gas cap and a large underlying aquifer. Well G-18 is a vertical producer in the 37B sand that penetrates the oil column and aquifer with only 11' of net pay. The well has produced over 500MSTB. However, because the completion lacked a means of artificial lift, flowrates were restricted once water production began. Eventually, the well was only capable of intermittent flow. A material balance analysis indicated the minimum original oil in place (OOIP) of 4.5 MMSTB with a strong water support. This volume estimate was also supported by seismic analysis and geological correlations. A reservoir simulation study was conducted with an aim to improve the oil recovery by investigating several production strategies. Since there is a free source of CO 2 gas available, an evaluation of CO2 miscible flooding was also conducted. Results show that the minimum miscibility pressure (MMP) is much higher than the reservoir pressure and miscible gas injection is not suitable for this reservoir. The presence of a small gas cap and a strong bottom water drive led to the decision to drill a horizontal well. Simulation shows that a 1,000' long, horizontal well optimally placed in the gas cap is the simplest and best strategy to recover more oil from this reservoir. The estimated incremental oil recovery is 1.2 MMSTB.
Performance results after drilling show that the well is an economic success and also proves that the same integrated team approach can be used successfully in the development of other analogous reservoirs with similar geology. The economic success of this well also shows that there is a potential for additional oil reserves in the shallow zones above the current pay window. To date, as many as 40 additional prospects have already been identified for horizontal well candidates to further the oil development for the field.
Introduction
Most of Unocal operated fields in the Pattani Basin are gas fields. The location of these fields is shown in Fig. 1. The geology predominantly consists of stacked reservoir systems with hundreds of small reservoirs distributed over a 6000' interval (between 4,000' to 10,000' below sea level). The sands are thin and have small area with average thickness of 14 ft and areal extent of 30 acres. A typical well drilled in the Pattani Basin would penetrate 10 or more of these sands. Out of more than 1,300 wells drilled within operated concessions, only three horizontal wells were drilled. The main reason is that most of these wells are designed to maximize the penetrations of these small, stacked gas sands. A recent comprehensive plan with focus on development of thin-oil reservoirs has lead to more horizontal drilling.
Development History
The 37B sand in the Platong field has a 30-foot oil column in between a small gas cap and an aquifer. The size of the reservoir is approximately 130 acres and at the depth of 3715' below sea level. This reservoir was discovered through Well G-18 that was drilled in 1999 as part of a gas infill program. The well did not encounter significant pay other than a small, thin, apparent gas sand. The well was completed serendipitously as it had a low pay count, and the decision to complete this well was made based on economics on the cost of a tubing run. The well was put on production and much to our surprise, the well produced oil instead of gas at a prodigious rate. After production continued for some time indicating a substantial reservoir, as the initial expectation was that the reservoir would deplete quickly, a concerted effort to determine the source of the oil and the size of the reservoir was warranted.
Numerous case studies substantiate the merit of horizontal drilling, especially in coning situations. Nonetheless, the burning question remains: do horizontal wells assure performance optimization in all cases? This paper explores the effectiveness of horizontal wells in a high-permeability (kh > 3,000 md), high-anisotropy (kv/kh < 0.01) Burgan Third Middle Sand (3MS) reservoir in Kuwait. To do so we built a sector model containing 35 wells to match 50-year history in a strong edge-water-drive system. With the history-matched model, we examined performance of horizontal wells under various scenarios. These scenarios included reservoir and completion considerations, such tubing size, well length, and high-slant configuration. For comparison, we measured the performance of a horizontal well against its vertical counterpart in terms of water-breakthrough time, oil acceleration, and incremental recovery.
Results show that horizontal wells do not appear to offer any decisive advantage over their vertical counterparts in terms of breakthrough time and ultimate recovery. That is because unique reservoir characteristics, such as high-anisotropy (kv/kh) and low-length-to-thickness (L/h) ratios, coupled with high productivity index (PI), all contributed adversely to horizontal wells' performance when compared with vertical wells. Horizontal wells' PI may be higher but the vertical well is equal to the task of delivering desired oil rates, although with a somewhat larger drawdown. In essence, the primary constraint on well performance is the tubing size, not PI. Therefore, a well with large tubing will achieve optimal performance, regardless of its orientation in the 3MS reservoir.
Exploitation of ultra-thin oil columns under gas cap and water support is challenging since both gas and water coning can seriously curtail oil recovery. Horizontal wells have shown to alleviate some of this problem as they allow for less drawdown and hence reduce coning for better recovery efficiency. Although the industry has shown horizontal drilling cost continues to be lowered, economics is still a major issue in exploiting ultra-thin oil bands using horizontal completion.
This paper presents a case study showing lessons learned from managing reservoirs with ultra-thin oil bands with less than 20 ft and sandwiched between gas cap and bottom/edge aquifer. Actual data from a field characterized by stacked pays of fluvial and deltaic channel sands in the Mahakam Delta complex are demonstrated. Subject to long-term production, the originally thick oil columns in these reservoirs have now become thinner, yet carry significant reserves to be prudently further developed. Issues involved in reservoir management such as well surveillance, well planning and prognosis, operating while drilling and producing, and long-term development plans are discussed. Reservoir modeling is shown to be the guide not only for well planning but also for well operations as it is used to select well type and completion strategy, optimize well production and prepare for continuous annual operating plan.
The vast well performance database provided from the paper shows horizontal drilling continues to be the main vehicle to develop these ultra-thin oil bands. Care however needs to be taken to scrutinize the economics inherent in selecting this type of completion, as other alternative methods also deserve to be considered.
This paper proposes completion strategies to target the remaining oil, left behind when water invades the producing interval(s) in bottom- and edge-water-drive reservoirs. In the first option, a conventional horizontal well is completed below the gas/oil contact (GOC). Once the completion waters out, recompletion occurs in the gas zone.
For either drive mechanism, recompletion of the vertical segment of the same wellbore at the crest is prudent, provided economic gas disposition is not an issue. In the second option, one can initially complete at the same location where the recompletion occurs, thereby skipping the initial completion. In all cases, gravity-stable flooding or disciplined withdrawal rate is required to maximize reserves.
Extensive flow simulations in multiple, history-matched models show that the proposed strategy improves oil recovery significantly. We show that the proposed completion strategies do not involve production of total cumulative gas/oil ratio any higher than those done with conventional completion involving much less oil recovery. In fact, the two-stage depletion scheme doubles the recovery factor in a saturated reservoir with a 34-ft oil column, which is underlain by a moderate size aquifer.
Beyond the computational results, several field examples demonstrate the usefulness of the proposed completion methods. We show that the normalized GOR or the cumulative gas production is less than those experienced under conventional depletion schemes because of gravity-stable flooding.
Thin oil columns represent a common and important class of hydrocarbon reserve which are notoriously difficult to evaluate and produce. This paper provides case studies of examples of these reservoirs in Australia and summarises the production methods, well performance and recovery efficiencies.Thin oil column reservoirs are defined here as reservoirs which will cone both water and gas when produced at commercial rates. The oil zone can have a pancake or rim geometry. Examples within Australia include Bream and Snapper (Gippsland Basin), South Pepper and Chervil (Carnarvon Basin), Chookoo (Eromanga Basin) and Taylor (Surat Basin).Parameters which are particularly important in defining the performance of these reservoirs are: horizontal and vertical permeability, column height, stratigraphie dip, well spacing, and oil viscosity. High horizontal permeability is more critical than in other reservoir types as it controls the effectiveness of gravitational forces in opposing coning and other unwanted flows by reducing pressure gradients. Low vertical permeability mitigates coning but can limit across strike drainage in dipping strata. Oil viscosity is also particularly important, even when the mobility ratio is favourable, as it controls the gas/oil ratio and water cut during coning.As coning (by definition) is inevitable the key production issue is gas cap management. The main options are:Limit gas coning by controlling completion depth and production rates.Allow gas cap shrinkage and 'chase' the oil column upwards via recompletions.Reinject gas to control gas-oil contact position.For the latter two options in particular, ultimate reserves are a strong function of the capacity of the installed production facilities, especially offshore, where fixed operating costs are high. When gas cap management is not compromised, reserves increase with higher total fluid withdrawal rates. Examples of the various gas cap management and production strategies are included.Both horizontal (South Pepper, Bream) and conventional (Chookoo, Taylor) completion techniques have been applied to thin oil column reservoirs in Australia. Horizontal completions can increase productivity, mitigate coning and increase the well drainage areas (particularly if drilled across dip in heterogeneous reservoirs). However, horizontal completions are particularly vulnerable to poor cement jobs, natural fractures and undesirable fluid contact movements.A variety of other completion techniques have been tried worldwide in thin oil columns with mixed success. These include multiple completions in the water, oil and/or gas to allow separate production, and injection of fluids to make permeability barriers or alter relative permeability.A number of scaling rules are included to assist in using offset field data for evaluation of thin oil column reservoirs. Improved understanding of these complex reservoirs will maximise their economic potential.
Exploitation of thin oil columns sandwiched between a gas cap and water leg poses a unique challenge for development of such reservoirs worldwide, especially for those with high permeability and strong aquifer support. Issues important for reservoir management involve locating the current fluid contacts and optimizing well placement, as coning effects from both gas and water could severely hinder recovery. The paper presents a field case study demonstrating the use of horizontal wells to improve oil recovery for thin oil columns affected by gas-cap and active water support. The paper discusses reservoir management practices applied, varying from use of reservoir modeling for identifying current fluid contacts to selection of completion strategies for optimizing oil recovery. A practical and cost-effective methodology, from reservoir modeling to landing horizontal wells, is discussed. Specific guidelines to complete wells in thin oil columns with respect to gas-cap size, well placement, spacing, well length, and rate control are provided. Field data from Serang Field in the Kutei Basin of East Kalimantan are discussed. These examples demonstrate thin oil columns under water drive can be effectively exploited with horizontal wells via integration of technology and a multi-disciplined team environment.
Computational considerations in obtaining well responses and pressure distributions for several problems presented in Part 1 are discussed. In addition, new asymptotic expressions for pressure distributions in closed drainage volumes applicable during the boundary-dominated flow period are derived. Interestingly, these expressions, which are much simpler than those available in the literature, can be used to derive shape factors for a variety of completion conditions (vertical, horizontal, and vertically fractured wells). Application of constant-rate solutions to more complex conditions is also presented.
The Helder oil field on the Dutch Continental Shelf was virtuallyredeveloped with the drilling of eight horizontal wells from Dec. 1986 to Jan.1988. The first horizontal well came on production Jan. 5, 1987. The success ofthese wells, all sidetracked from existing wells and the first horizontal wellsin the North Sea, led to a complete reappraisal of Unocal Netherland B.V.'sreservoir development philosophy. This paper reviews the background, performance, and benefits of the Helder field performance, and benefits of theHelder field horizontal wells through April 1988.
Introduction
The major benefits of horizontal wells (i.e., increased productivity andimproved sweep efficiency) have been recognized for some time from a reservoirmanagement point of view. The main obstacles to realizing these benefits havebeen the technical difficulty and high cost of drilling horizontal wells. WhenUnocal Netherlands B.V. began investigating the possibility of drillinghorizontal wells (mid-1986), the literature indicated that the cost of thesewells would be four to six times that of equivalent conventional wells.
The economic success of the Helder field horizontal wells is attributablemainly to improved drilling technology and planning. Ref. 1 describes thedrilling aspects of these wells.
This paper discusses the reservoir engineering aspects of the horizontalwells drilled in the Helder field, including (1) justification for and choiceof the first well, (2) field redevelopment, (3) performance and benefits, and (4) optimum production rate.
It also briefly describes the drilling andcompletion method.
Field History
The Helder field is located in Block Q/1 of the Dutch North Sea, about 62miles [100 km] northwest of Amsterdam, and lies in 85 ft [26 m] of water (Fig.1). Block Q/1 was acquired by Unocal Netherlands B.V. and its partner NedlloydEnergy B.V. in 1967. The field was discovered in April 1979 and productionbegan in Oct. 1982. Two other production began in Oct. 1982. Two other oilfields, Helm and Hoorn, were brought on production during this time. Helm fieldproduction began in Oct. 1982, and Hoorn production began in Oct. 1982, andHoorn began in July 1983. These three fields (Fig. 2) represent the firstcommercial oil production from the Dutch sector of the North Sea. productionfrom the Dutch sector of the North Sea. Between 1982 and 1984 the Helder fieldwas developed with 12 conventional wells from a centrally located wellheadplatform. In 1986, a previously drilled appraisal well (Well Q/1-10) was tiedback to Helder field's Platform A with a satellite tripod tower, Platform B. All the original wells were completed with gravel packs for sand control.
Although some wells were initially produced under natural flow, electricproduced under natural flow, electric submersible pumps (ESP's) were eventuallyinstalled in all wells to compensate for declining reservoir pressure andincreasing water cut. The maximum size of the first pumps was limited to 83.5hp [62.3 kW] pumps was limited to 83.5 hp [62.3 kW] because of platformpower-supply limitations. In 1985 and 1986, increasing water cuts andcontinuously declining reservoir pressure led to the installation of additionalpower generation equipment to enable larger pumps (250 hp [187 kW]) to berun.
Before production started on the first horizontal well (Jan. 1987), Helderfield produced 6,530 BOPD [1038 m3/d oil] for produced 6,530 BOPD [1038 m3/doil] for a gross fluid offtake of 108,000 BFPD [17 170 m3/d fluid]. Individualwells produced at rates up to 12,000 BFPD [1908 produced at rates up to 12,000BFPD [1908 m3/d fluid], with water cuts between 84 and 97%.
Helder Field Description
Helder field (Figs. 3 and 4) is a small accumulation of 22 degrees API[0.92-g/cm3] -specific-gravity crude in a relatively simple, slightly faulted, anticlinal structure at a depth of 4,600 ft [1402 m]. Original oil in place isestimated to be 70 MMSTB [11.2 X 106 stock-tank m3]. Production is from theLower Cretaceous Vlieland sandstone, which has excellent reservoircharacteristics and permeabilities that range from 1.0 to 6.0 darcies. Thesandstone is friable and of intermediate wettability and contains a partiallybiodegraded oil with a 30-cp [0.03-Pa.s] viscosity. The field is underlain bywater over its entire 1,140 acres [461 ha] of closure and has a maximum oilcolumn of 131 ft [40 m].
Pre-1987 Field Pre-1987 Field Development Philosophy
Early water breakthrough and rapidly increasing water cut were expected inthe original wells because of the high viscosity ratio, the flat fieldstructure, and the high vertical permeability of the sand. The majority ofwells produced water within a few days of production startup (Table 1).
This paper presents the results of two long-term horizontal well tests in the Troll field. Planning and evaluation of the tests and simulation of and consequences on field development are summarized. The two tests demonstrated significant production potential from 12- to 22-m oil columns and verified the pretest assumption that one horizontal well could replace four vertical wells.
Introduction
The Troll field, in 300-m-deep-water offshore Norway, contains oil rims of varying thicknesses between the overlaying gas and the aquifer below. The field is divided into three main provinces: Troll West oil province, 22- to 26-m oil column; Troll West gas province, ˜12-m oil column; and Troll East, 0- to 4-m oil column. The oil in place in the two provinces with the thickest oil columns was estimated to be 155 and 440 × 106 std m3, respectively (Fig. 1).
The reservoir in the Troll field consists of dipping, highly permeable (3 to 10 µm2) clean sands interbedded with dipping micaceous and silty to fine-grained sands of significantly lower permeability (in the 1-µm2 range). The sands are highly unconsolidated. Calcite cementation occurs in all lithologies over the entire field. The calcites can be divided into two classes on the basis of their assumed lateral extensions. Regional calcites are thought to be sheets up to several kilometers wide occurring at boundaries between geologic zones, whereas local calcites are thought to be less extensive (1 to 100 m) and to occur within the geologic zones.
The highly permeable clean sands, C sands, are the target sands for the horizontal wells and contain 60% to 75% of the oil in place; the remaining oil is contained within the micaceous sands, M sands, which are hard to drain under the conditions in Troll. The dipping sands and the thin oil columns result in elongated target areas for the wells (Fig. 2).
The Troll reservoir, at the shallow depth of 1300 to 1570 m below mean sea level, is at hydrostatic pressure. The oil viscosity in Troll West varies between 1.3 and 1.8 mPa's. Table 1 lists reservoir and fluid properties. In parts of the field, a residual oil zone exists below the oil/water contact (OWC). The relative permeability to water at 25% residual oil saturation (ROS) is low, from 0.05 to 0.40.
Oil production will be limited by gas coning, which results in a rapidly decreasing liquid rate, and the increasing water cut reduces the oil rate even further. In general, horizontal wells are known to improve productivity and to reduce coning problems compared with conventional vertical wells.1–4
For the Troll field, pretest simulation studies indicated that development of the Troll West oil province based on 500-m wells could be economically attractive. However, owing to such factors as 300-m-deep water, a highly unconsolidated reservoir rock, and a thin oil column, the development was considered to be a high-risk project. To confirm the horizontal-well potential and long-term behavior, and thereby reduce the risk involved, an 11-month long-term test with a 500-m horizontal well positioned 3 m above the OWC was carried out in the Troll West oil province during 1990.
The Troll West oil and gas provinces previously had been subject to studies aimed at commercial development of the large oil accumulation. However, no sound economy was found in these studies, which were based on the use of vertical wells. Encouraged by the good results obtained from the first horizontal test well, a new study was initiated that based a Troll West gas province development on the use of horizontal wells. The uncertainties related to the Troll West gas province development were assumed to be even larger than for the Troll West oil province owing to a need for increased well length and the thinner oil column. Therefore, a long-term test was carried out in the Troll West gas province immediately after the Troll West oil province test ended. The second horizontal test well was 800 m long and target depth for the horizontal section was 1 m above the OWC. This target depth required improved drilling accuracy.
Long-Term Tests
The objectives of the first long-term production test with a horizontal well in the Troll West oil province were to gain experience and information on the most important uncertainties.5,6 The tests were intended to demonstrate the viability of drilling and completing a horizontal well in the highly unconsolidated Troll sands; to verify the theoretically expected productivity increase and reduced coning compared with those in vertical wells; and to observe time to gas breakthrough, water-cut development, critical oil rate trend, and possible hysteresis effects.
The experience and encouraging results obtained from the first test well were also the basis for planning and deciding to drill the second test well in the Troll West gas province and for performing a shorter, but similar, test program.
The objectives of the second test well were (1) to confirm the viability of extending the horizontal section from 500 to 800 m; (2) to improve drilling accuracy by use of pressure and resistivity measurements while drilling; (3) to verify pretest predictions of increased oil rate, delayed gas breakthrough, and reduced water-cut development; and (4) to evaluate oil production above critical rates (supercritical production).
The information from the two tests has been used (1) to verify the technique for improved drilling accuracy; (2) to calibrate the various reservoir simulation models, well and full field; (3) to adjust geologic and reservoir parameters through the history-matching process; (4) to verify relative permeabilities from the first history match by using them in the second test match; and (5) to establish more optimal development schemes, with reduced uncertainty, involving supercritical production in the Troll West gas province and longer wells in the Troll West oil province.
Figs. 3 and 4 show the ranges of oil rate and cumulative oil production from the pretest simulations for various geologic and reservoir sensitivities compared with actual performance of the two test wells.
Horizontal Test Well Locations
The following reasoning formed the basis for deciding on locations for the horizontal test wells (Fig. 1):both wells are in areas that contain major amounts of assumed reserves of the region;drilling a high number of development wells is planned in and near the two tested areas;both wells are close to previously cored exploration wells - particularly important in the case of the uncored Troll West oil province well; andcomparison of vertical and horizontal well performance was facilitated because the horizontal test wells were close to existing tested vertical exploration wells.
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This paper presents a Gulf of Mexico field case study describing the use of horizontal wells to improve oil recovery in thin attic-oil, strong waterdrive reservoirs. Prewell planning shows the use of reservoir simulation for well performance forecasts, discusses selection of drilling mud for minimal damage, logging while drilling (LWD) for steering and optimal completion techniques. Post-well results show that horizontal wells, applied with an integration of technology, not only help accelerate production but also improve oil recovery compared with conventional wells for this type of reservoir problem.
Yakin field, operated by Unocal Indonesia Co. was discovered in May 1976. The field was divided into three separate fault blocks and located offshore Balikpapan in 15-ft water depth. By the end of year 1996, the field had produced 33.9 MMBO and 25.2 BCF gas. The field’s daily production had declined to 2,900 BOPD and 4.4 MMSCFD gas from 19 producing old wells scattered on small platforms.
Prior to 1997, a transition zone 3D seismic was acquired over the whole area identifying potential for additional reserve recovery. Development drilling had not been done for eleven years due to high drilling cost to develop marginal reserves. The field is located in shallow water depth with platform size limiting drilling operations to a jack-up and workovers to a snubbing unit. However, with the innovation of a new wellhead platform structure, a less expensive tender supported rig could be used. Cost reductions in development drilling, made marginal reserves economic.
Field performance review, geological and 3D seismic work, pilot wells and reservoir simulation indicated reservoir development potential in the field through the application of horizontal drilling technology. In 1997 an additional fourteen wells were drilled and completed in Yakin field. With the addition of these new wells, the total field production increased to 7,200 BOPD. The cheaply drilled horizontal wells, were found suitable for controlling sand production in the unconsolidated Yakin reservoirs.
Indonesian Petroleum Association, 23rd Annual Convention
- T Clark
- J Hadiwijoto
- B Zagalai
- M Martinez
- D Staples