{"id":"well-testing-productivity-index-drawdown-ipr-engineering-guide","canonicalSlug":"well-testing-productivity-index-drawdown-ipr-engineering-guide","url":"https://wellficent.com/en/news/well-testing-productivity-index-drawdown-ipr-engineering-guide","language":"en","title":"Well Testing and Productivity Index: Drawdown, Units and an IPR Example","summary":"A reproducible petroleum engineering guide to pressure drawdown, single-phase productivity, test uncertainty and the limits of linking calculations to Well Atlas records.","body":["A production rate becomes useful engineering evidence only when its pressure, fluid, time and measurement basis are known. A large daily rate alone cannot establish reservoir quality, sustainable deliverability or the benefit of a workover. The first task is to identify what was measured and where, before fitting a performance relationship.","This guide separates source definitions, a deliberately hypothetical calculation and a real research pathway. Every number in the worked example is prescribed for teaching. None is a measurement, forecast or operating limit for the linked SODIR wellbore. The illustration is AI-generated conceptual artwork of a fictional surface installation, not a test schematic or project photograph."],"keyPoints":[],"sections":[{"heading":"Define drawdown at a common pressure datum","paragraphs":["SLB defines production-test drawdown as the difference between average reservoir pressure and flowing bottomhole pressure. Write Δp = p̄r − pwf. Both pressures must refer to a compatible reservoir depth and pressure reference; use absolute pressure consistently here. A wellhead pressure cannot simply replace sandface pressure. Wellbore fluid head and flowing friction separate those measurement locations.","Record gauge depth, datum, calibration, timestamp and whether a quoted pressure is measured or calculated. Measured depth follows the borehole, whereas true vertical depth controls a simple hydrostatic head. The linked depth and drilling-pressure guides explain these distinctions. A static drilling-fluid pressure calculation does not supply flowing reservoir pressure or a production-test interpretation."]},{"heading":"State the productivity definition and the phase assumptions","paragraphs":["The productivity index J expresses a compatible production rate per unit drawdown: J = q/Δp. For the present example q means stock-tank oil rate in STB/day, so J has units STB/day/psi. Retain the declared surface reference conditions. Reservoir barrels, total liquid, oil and gas-equivalent rates cannot silently share that numerator.","A constant-J relation q = J(p̄r − pwf) is assumed only over the example pressure range for single-phase liquid inflow, with effectively unchanged fluid properties and test conditions. It is not a universal oil-well law. SLB describes an inflow performance relationship as rate versus flowing bottomhole pressure and explains that fluid composition and phase behaviour affect its shape. Gas evolution or multiphase flow requires an appropriate model and supporting fluid data."]},{"heading":"Reproduce the fictional reference point","paragraphs":["Prescribe p̄r = 4,000 psia, pwf = 3,000 psia and q = 500 STB/day. The drawdown is 1,000 psi, and J = 500/1000 = 0.5 STB/day/psi. For this teaching exercise also assume a bubblepoint of 2,000 psia and single-phase inflow throughout the evaluated pressure range. These are assumptions, not laboratory PVT results.","Hold reservoir pressure and J fixed. At pwf = 3,500, 3,000 and 2,500 psia, the corresponding drawdowns are 500, 1,000 and 1,500 psi. Multiplication by 0.5 gives 250, 500 and 750 STB/day. The accompanying chart and table contain exactly these calculated scenarios. They are not three observed test points or evidence that any real well can reach the largest rate."]},{"heading":"Bound the arithmetic uncertainty honestly","paragraphs":["Now prescribe independent bounds for the reference point: oil rate 500 ± 25 STB/day, reservoir pressure 4,000 ± 50 psia and flowing pressure 3,000 ± 50 psia. The extreme compatible drawdowns are 900 and 1,100 psi. Combining the lowest rate with the largest drawdown gives Jmin = 475/1100 = 0.431818; combining the highest rate with the smallest drawdown gives Jmax = 525/900 = 0.583333 STB/day/psi.","This is a worst-case interval under the stated bounds, not a confidence interval, probability distribution or instrument specification. Correlated pressure errors, changing fluid properties and model error are not quantified. The interval describes arithmetic sensitivity at the reference point; it does not validate the constant-J assumption or quantify future production uncertainty."]},{"heading":"Treat a test as a pressure-and-rate history","paragraphs":["SLB distinguishes drawdown, buildup, injection and interference tests, and describes pressure-transient analysis using pressure, rate and time. A pressure recorded shortly after shut-in is not automatically a representative average reservoir pressure. Interpretation needs the preceding rate history, test duration, gauge location and an assessment of the flow regime.","A practical review should retain the unedited time series, rate changes, shut-in events, separator conditions, water and gas measurements, calibration records and quality flags. Align clocks before combining pressure and flow. Distinguish a stabilized test rate from an initial peak, an allocation estimate and a monthly average. Without those distinctions, dividing two reported numbers may produce a precise-looking index with no defensible physical meaning."]},{"heading":"Do not diagnose skin or select artificial lift from one ratio","paragraphs":["Skin is a dimensionless representation of impaired or enhanced near-well performance relative to a theoretical reference. A lower apparent J can also accompany different reservoir pressure, fluid state, completion conditions or an inconsistent measurement basis. One rate-pressure pair cannot independently determine permeability, skin and reservoir boundaries. Those quantities require a suitable interpretation with additional evidence.","Likewise, an inflow curve alone does not select a pump, choke or safe production rate. The surface operating point also depends on wellbore and facility pressure requirements, fluid behaviour and equipment constraints. This article supplies no tubing-performance model, sand-control criterion, drawdown limit or intervention recommendation. The fictional 750 STB/day scenario is a multiplication result, not a field instruction."]},{"heading":"Follow a real record without borrowing its identity","paragraphs":["The cited Well Atlas entry no-sodir-112 identifies SODIR source record 112, wellbore 16/11-1 S. Its source page and the existing research interface provide an explicit route to retained documents and test summaries. Inspect each test’s own dates, units and depth references. The presence of a test summary or a shared well name does not establish that it contains the complete, compatible inputs needed for this worked example.","No pressure or rate from that well was used to calculate the chart. Its registry identity is not a verified physical join to another catalogue, a producing-field allocation or a refinery supply relationship. Keep missing inputs unknown. Use the related production-data guide when moving from test rates to calendar-period observations; those are different reporting products with different denominators."]},{"heading":"Keep a reproducible evidence package","paragraphs":["A reviewable productivity estimate should travel with its exact source record, fluid and rate basis, common pressure datum, observation period, calculation, assumptions and limitations. Preserve the original values beside any conversion. Store a calculated index separately from measured pressure and rate, and label fitted or forecast output explicitly. A later source review date does not make old measurements newly observed.","The example can be independently reproduced with division, subtraction and multiplication; no fitted reservoir model or accuracy claim is involved. For an actual study, obtain the missing test history and fluid information before interpreting a curve. This preserves a useful connection between educational petroleum engineering and real records without manufacturing reservoir properties or operational certainty."]}],"text":"Well Testing and Productivity Index: Drawdown, Units and an IPR Example\n\nA reproducible petroleum engineering guide to pressure drawdown, single-phase productivity, test uncertainty and the limits of linking calculations to Well Atlas records.\n\nA production rate becomes useful engineering evidence only when its pressure, fluid, time and measurement basis are known. A large daily rate alone cannot establish reservoir quality, sustainable deliverability or the benefit of a workover. The first task is to identify what was measured and where, before fitting a performance relationship.\n\nThis guide separates source definitions, a deliberately hypothetical calculation and a real research pathway. Every number in the worked example is prescribed for teaching. None is a measurement, forecast or operating limit for the linked SODIR wellbore. The illustration is AI-generated conceptual artwork of a fictional surface installation, not a test schematic or project photograph.\n\nDefine drawdown at a common pressure datum\n\nSLB defines production-test drawdown as the difference between average reservoir pressure and flowing bottomhole pressure. Write Δp = p̄r − pwf. Both pressures must refer to a compatible reservoir depth and pressure reference; use absolute pressure consistently here. A wellhead pressure cannot simply replace sandface pressure. Wellbore fluid head and flowing friction separate those measurement locations.\n\nRecord gauge depth, datum, calibration, timestamp and whether a quoted pressure is measured or calculated. Measured depth follows the borehole, whereas true vertical depth controls a simple hydrostatic head. The linked depth and drilling-pressure guides explain these distinctions. A static drilling-fluid pressure calculation does not supply flowing reservoir pressure or a production-test interpretation.\n\nState the productivity definition and the phase assumptions\n\nThe productivity index J expresses a compatible production rate per unit drawdown: J = q/Δp. For the present example q means stock-tank oil rate in STB/day, so J has units STB/day/psi. Retain the declared surface reference conditions. Reservoir barrels, total liquid, oil and gas-equivalent rates cannot silently share that numerator.\n\nA constant-J relation q = J(p̄r − pwf) is assumed only over the example pressure range for single-phase liquid inflow, with effectively unchanged fluid properties and test conditions. It is not a universal oil-well law. SLB describes an inflow performance relationship as rate versus flowing bottomhole pressure and explains that fluid composition and phase behaviour affect its shape. Gas evolution or multiphase flow requires an appropriate model and supporting fluid data.\n\nReproduce the fictional reference point\n\nPrescribe p̄r = 4,000 psia, pwf = 3,000 psia and q = 500 STB/day. The drawdown is 1,000 psi, and J = 500/1000 = 0.5 STB/day/psi. For this teaching exercise also assume a bubblepoint of 2,000 psia and single-phase inflow throughout the evaluated pressure range. These are assumptions, not laboratory PVT results.\n\nHold reservoir pressure and J fixed. At pwf = 3,500, 3,000 and 2,500 psia, the corresponding drawdowns are 500, 1,000 and 1,500 psi. Multiplication by 0.5 gives 250, 500 and 750 STB/day. The accompanying chart and table contain exactly these calculated scenarios. They are not three observed test points or evidence that any real well can reach the largest rate.\n\nBound the arithmetic uncertainty honestly\n\nNow prescribe independent bounds for the reference point: oil rate 500 ± 25 STB/day, reservoir pressure 4,000 ± 50 psia and flowing pressure 3,000 ± 50 psia. The extreme compatible drawdowns are 900 and 1,100 psi. Combining the lowest rate with the largest drawdown gives Jmin = 475/1100 = 0.431818; combining the highest rate with the smallest drawdown gives Jmax = 525/900 = 0.583333 STB/day/psi.\n\nThis is a worst-case interval under the stated bounds, not a confidence interval, probability distribution or instrument specification. Correlated pressure errors, changing fluid properties and model error are not quantified. The interval describes arithmetic sensitivity at the reference point; it does not validate the constant-J assumption or quantify future production uncertainty.\n\nTreat a test as a pressure-and-rate history\n\nSLB distinguishes drawdown, buildup, injection and interference tests, and describes pressure-transient analysis using pressure, rate and time. A pressure recorded shortly after shut-in is not automatically a representative average reservoir pressure. Interpretation needs the preceding rate history, test duration, gauge location and an assessment of the flow regime.\n\nA practical review should retain the unedited time series, rate changes, shut-in events, separator conditions, water and gas measurements, calibration records and quality flags. Align clocks before combining pressure and flow. Distinguish a stabilized test rate from an initial peak, an allocation estimate and a monthly average. Without those distinctions, dividing two reported numbers may produce a precise-looking index with no defensible physical meaning.\n\nDo not diagnose skin or select artificial lift from one ratio\n\nSkin is a dimensionless representation of impaired or enhanced near-well performance relative to a theoretical reference. A lower apparent J can also accompany different reservoir pressure, fluid state, completion conditions or an inconsistent measurement basis. One rate-pressure pair cannot independently determine permeability, skin and reservoir boundaries. Those quantities require a suitable interpretation with additional evidence.\n\nLikewise, an inflow curve alone does not select a pump, choke or safe production rate. The surface operating point also depends on wellbore and facility pressure requirements, fluid behaviour and equipment constraints. This article supplies no tubing-performance model, sand-control criterion, drawdown limit or intervention recommendation. The fictional 750 STB/day scenario is a multiplication result, not a field instruction.\n\nFollow a real record without borrowing its identity\n\nThe cited Well Atlas entry no-sodir-112 identifies SODIR source record 112, wellbore 16/11-1 S. Its source page and the existing research interface provide an explicit route to retained documents and test summaries. Inspect each test’s own dates, units and depth references. The presence of a test summary or a shared well name does not establish that it contains the complete, compatible inputs needed for this worked example.\n\nNo pressure or rate from that well was used to calculate the chart. Its registry identity is not a verified physical join to another catalogue, a producing-field allocation or a refinery supply relationship. Keep missing inputs unknown. Use the related production-data guide when moving from test rates to calendar-period observations; those are different reporting products with different denominators.\n\nKeep a reproducible evidence package\n\nA reviewable productivity estimate should travel with its exact source record, fluid and rate basis, common pressure datum, observation period, calculation, assumptions and limitations. Preserve the original values beside any conversion. Store a calculated index separately from measured pressure and rate, and label fitted or forecast output explicitly. A later source review date does not make old measurements newly observed.\n\nThe example can be independently reproduced with division, subtraction and multiplication; no fitted reservoir model or accuracy claim is involved. For an actual study, obtain the missing test history and fluid information before interpreting a curve. This preserves a useful connection between educational petroleum engineering and real records without manufacturing reservoir properties or operational certainty.\n\nTechnical and economic analysis\n\nAnalysis as of: 2026-11-15\n\nEvidence cutoff: 2026-11-15\n\nOutlook horizon: Hypothetical single-phase inflow; no forecast horizon\n\nIllustrative sensitivity\n\nFictional constant-productivity inflow scenarios\n\nCalculated scenarios, not observations: q = 0.5 × (4000 − pwf). At pwf 3500 / 3000 / 2500 psia, q is 250 / 500 / 750 STB/day. Reservoir pressure, J and bubblepoint 2000 psia are prescribed; no SODIR 112 inputs or safe-rate claim.\n\nThese calculations illustrate stated assumptions; they are not observations or a calibrated forecast.\n\nAssumed flowing pressure: 3500 psia: 250 stock-tank oil barrels per day\n\nAssumed flowing pressure: 3000 psia: 500 stock-tank oil barrels per day\n\nAssumed flowing pressure: 2500 psia: 750 stock-tank oil barrels per day","category":"energy","region":"world","topics":["oil","gas"],"eventDate":"2026-11-15","eventDateBasis":"analysis-as-of","publishedAt":"2026-11-15T15:51:37Z","modifiedAt":"2026-11-15T15:51:37Z","publicationBasis":"first-publication","preparedAt":"2026-11-15T15:50:59Z","sourcePublishedAt":null,"translatedAt":null,"sources":[{"url":"https://glossary.slb.com/terms/p/productivity_index_pi","name":"SLB Energy Glossary — productivity index (PI)","checkedAt":"2026-11-15"},{"url":"https://glossary.slb.com/en/terms/d/drawdown","name":"SLB Energy Glossary — drawdown","checkedAt":"2026-11-15"},{"url":"https://glossary.slb.com/en/terms/i/inflow_performance_relationship","name":"SLB Energy Glossary — inflow performance relationship","checkedAt":"2026-11-15"},{"url":"https://www.slb.com/resource-library/oilfield-review/defining-series/defining-well-testing","name":"SLB — The Defining Series: Well Testing Fundamentals","checkedAt":"2026-11-15"},{"url":"https://glossary.slb.com/en/terms/s/skin","name":"SLB Energy Glossary — skin","checkedAt":"2026-11-15"},{"url":"https://factpages.sodir.no/en/wellbore/pageview/with/welllogs/112","name":"Norwegian Offshore Directorate — wellbore 16/11-1 S, source record 112","licence":"NLOD 2.0 — source-specific terms apply","checkedAt":"2026-11-15","licenseUrl":"https://data.norge.no/nlod/en/2.0","attribution":"Norwegian Offshore Directorate; the fictional calculation is not source measurement data."},{"url":"https://wellficent.com/en/wells/record/no-sodir-112","name":"Wellficent Well Atlas — retained source record no-sodir-112; not example inputs","checkedAt":"2026-11-15"},{"url":"https://wellficent.com/api/v1/research/wells/no-sodir-112","name":"Wellficent research API — source-scoped documents and test summaries for no-sodir-112","checkedAt":"2026-11-15"}],"translations":{"en":"https://wellficent.com/en/news/well-testing-productivity-index-drawdown-ipr-engineering-guide","tr":"https://wellficent.com/tr/news/well-testing-productivity-index-drawdown-ipr-engineering-guide","ar":"https://wellficent.com/ar/news/well-testing-productivity-index-drawdown-ipr-engineering-guide","fr":"https://wellficent.com/fr/news/well-testing-productivity-index-drawdown-ipr-engineering-guide","es":"https://wellficent.com/es/news/well-testing-productivity-index-drawdown-ipr-engineering-guide","ru":"https://wellficent.com/ru/news/well-testing-productivity-index-drawdown-ipr-engineering-guide","pt":"https://wellficent.com/pt/news/well-testing-productivity-index-drawdown-ipr-engineering-guide"},"corrections":[],"locations":[],"type":"analysis","analysis":{"asOf":"2026-11-15","kind":"technical-economic","chart":{"kind":"illustrative","note":{"ar":"سيناريوهات محسوبة لا مشاهدات: q = 0.5 × (4000 − pwf). عند pwf بقيم 3500 / 3000 / 2500 psia تكون q بقيم 250 / 500 / 750 STB/day. ضغط المكمن وJ وضغط الفقاعة 2000 psia مفروضة؛ لا مدخلات من SODIR 112 ولا ادعاء معدل آمن.","en":"Calculated scenarios, not observations: q = 0.5 × (4000 − pwf). At pwf 3500 / 3000 / 2500 psia, q is 250 / 500 / 750 STB/day. Reservoir pressure, J and bubblepoint 2000 psia are prescribed; no SODIR 112 inputs or safe-rate claim.","es":"Escenarios calculados, no observados: q = 0,5 × (4000 − pwf). Para pwf 3500 / 3000 / 2500 psia, q es 250 / 500 / 750 STB/día. Presión del yacimiento, J y presión de burbuja 2000 psia prescritos; sin entradas SODIR 112 ni afirmación de caudal seguro.","fr":"Scénarios calculés, non observés : q = 0,5 × (4000 − pwf). Pour pwf 3500 / 3000 / 2500 psia, q vaut 250 / 500 / 750 STB/jour. Pression du réservoir, J et pression de bulle 2000 psia imposés ; aucune donnée SODIR 112 ni débit sûr revendiqué.","pt":"Cenários calculados, não observações: q = 0,5 × (4000 − pwf). Para pwf 3500 / 3000 / 2500 psia, q é 250 / 500 / 750 STB/dia. Pressão do reservatório, J e pressão de bolha 2000 psia prescritos; sem entradas SODIR 112 nem alegação de vazão segura.","ru":"Расчётные сценарии, не наблюдения: q = 0,5 × (4000 − pwf). При pwf 3500 / 3000 / 2500 psia q равен 250 / 500 / 750 STB/сут. Давление пласта, J и давление насыщения 2000 psia заданы; данных SODIR 112 и утверждения о безопасном дебите нет.","tr":"Gözlem değil, hesaplanmış senaryolar: q = 0,5 × (4000 − pwf). pwf 3500 / 3000 / 2500 psia için q 250 / 500 / 750 STB/gün. Rezervuar basıncı, J ve 2000 psia kabarcık noktası verilmiştir; SODIR 112 girdisi veya güvenli debi iddiası yoktur."},"rows":[{"label":{"ar":"ضغط الجريان المفترض: 3500 psia","en":"Assumed flowing pressure: 3500 psia","es":"Presión fluyente supuesta: 3500 psia","fr":"Pression en écoulement supposée : 3500 psia","pt":"Pressão em fluxo suposta: 3500 psia","ru":"Условное давление при течении: 3500 psia","tr":"Varsayılan akış basıncı: 3500 psia"},"value":250},{"label":{"ar":"ضغط الجريان المفترض: 3000 psia","en":"Assumed flowing pressure: 3000 psia","es":"Presión fluyente supuesta: 3000 psia","fr":"Pression en écoulement supposée : 3000 psia","pt":"Pressão em fluxo suposta: 3000 psia","ru":"Условное давление при течении: 3000 psia","tr":"Varsayılan akış basıncı: 3000 psia"},"value":500},{"label":{"ar":"ضغط الجريان المفترض: 2500 psia","en":"Assumed flowing pressure: 2500 psia","es":"Presión fluyente supuesta: 2500 psia","fr":"Pression en écoulement supposée : 2500 psia","pt":"Pressão em fluxo suposta: 2500 psia","ru":"Условное давление при течении: 2500 psia","tr":"Varsayılan akış basıncı: 2500 psia"},"value":750}],"unit":"STB/day","title":{"ar":"سيناريوهات افتراضية لتدفق بإنتاجية ثابتة","en":"Fictional constant-productivity inflow scenarios","es":"Escenarios ficticios con productividad constante","fr":"Scénarios fictifs à productivité constante","pt":"Cenários fictícios de influxo com produtividade constante","ru":"Условные сценарии притока с постоянной продуктивностью","tr":"Kurmaca sabit üretkenlik giriş senaryoları"},"unitLabel":{"ar":"براميل نفط يومياً عند ظروف خزان التخزين","en":"stock-tank oil barrels per day","es":"barriles de petróleo a condiciones de tanque por día","fr":"barils d’huile aux conditions de bac par jour","pt":"barris de óleo em condições de tanque por dia","ru":"баррели нефти в условиях товарного резервуара в сутки","tr":"günlük stok tankı koşullarındaki petrol varili"}},"horizon":"Hypothetical single-phase inflow; no forecast horizon","horizonLabel":{"ar":"تدفق افتراضي أحادي الطور؛ لا أفق تنبؤ","en":"Hypothetical single-phase inflow; no forecast horizon","es":"Entrada monofásica hipotética; sin horizonte de pronóstico","fr":"Écoulement monophasique fictif ; aucun horizon prévisionnel","pt":"Influxo monofásico hipotético; sem horizonte de previsão","ru":"Условный однофазный приток; прогнозного горизонта нет","tr":"Varsayımsal tek fazlı giriş; tahmin ufku yok"},"evidenceCutoff":"2026-11-15"},"relatedArticles":[{"canonicalSlug":"drilling-hydrostatic-pressure-ecd-engineering-guide","url":"https://wellficent.com/en/news/drilling-hydrostatic-pressure-ecd-engineering-guide","title":"Drilling pressure: hydrostatics, ECD and the mud window","language":"en"},{"canonicalSlug":"well-log-depth-md-tvd-datum-engineering-guide","url":"https://wellficent.com/en/news/well-log-depth-md-tvd-datum-engineering-guide","title":"Well-log depth: MD, TVD and datum explained","language":"en"},{"canonicalSlug":"oil-gas-production-data-rates-boe-decline-engineering-guide","url":"https://wellficent.com/en/news/oil-gas-production-data-rates-boe-decline-engineering-guide","title":"Oil and gas production data: rates, boe, decline and value","language":"en"}],"image":{"url":"https://wellficent.com/media/1f29a2963e8afbca3e806e9d0ce4bbfada6783458136dbecf7d331681595d468.webp","width":1752,"height":897,"alt":"AI-generated conceptual illustration of a fictional wellhead, choke manifold, test separator and receiving tanks; not SODIR 112, a measured test or a validated layout.","credit":"Wellficent — AI-generated conceptual illustration, built-in imagegen, 15 November 2026. Fictional installation, not project photography or engineering evidence. OpenAI terms apply; source-data rights remain separate.","licenseUrl":"https://openai.com/policies/terms-of-use/"}}